**Exhibit 99.1**

 

**ANNUAL INFORMATION FORM**

** **

**For the Fiscal Year Ended December 31,2007**

 

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**ARC EnergyTrust**

 

**2007 AnnualInformation Form**

 

**March 24,2008**

 

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**TABLE OF CONTENTS**

** **
| ** **                                                      | ** ** | **Page** |
|-----------------------------------------------------------------|------------|----------|
|                                                            |       |     |
| GLOSSARY OF TERMS                                               |       | 1        |
| SPECIAL NOTES TO READER                                         |       | 2        |
| ARC ENERGY TRUST                                                |       | 4        |
| General                                                         |       | 4        |
| General Development of Our Business                             |       | 4        |
| OUR BUSINESS                                                    |       | 5        |
| Overview                                                        |       | 5        |
| Federal Tax Changes for Income Trusts and Corporations          |       | 5        |
| Our Organizational Structure                                    |       | 6        |
| ARC Sask Reorganization                                         |       | 7        |
| Management Policies                                             |       | 7        |
| Distributions and Distribution Policy                           |       | 7        |
| Capital Expenditures                                            |       | 7        |
| Potential Acquisitions                                          |       | 8        |
| STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS  INFORMATION   |       | 8        |
| Disclosure of Reserves Data                                     |       | 8        |
| Reserves Data (Constant Prices and Costs)                       |       | 9        |
| Reserves Data (Forecast Prices and Costs)                       |       | 11       |
| Definitions and Notes to Reserves Data Tables:                  |       | 13       |
| Reconciliations of Changes in Reserves                          |       | 17       |
| Additional Information Relating to Reserves Data                |       | 18       |
| Other Oil and Gas Information                                   |       | 19       |
| Marketing Arrangements                                          |       | 26       |
| Acquisitions and Dispositions                                   |       | 26       |
| SHARE CAPITAL OF ARC RESOURCES                                  |       | 27       |
| Common Shares                                                   |       | 27       |
| Exchangeable Shares                                             |       | 27       |
| Second Preferred Shares                                         |       | 28       |
| OTHER INFORMATION RELATING TO OUR BUSINESS                      |       | 28       |
| Borrowing                                                       |       | 28       |
| OUR INFORMATION                                                 |       | 29       |
| Trust Units                                                     |       | 29       |
| Special Voting Unit                                             |       | 29       |
| The Trust Indenture                                             |       | 29       |
| Trustee                                                         |       | 29       |
| Future Offerings                                                |       | 30       |
| Meetings and Voting                                             |       | 30       |
| Our Management                                                  |       | 30       |
| Limitation on Non-Resident Ownership                            |       | 31       |
| Right of Redemption                                             |       | 31       |
| Termination of the Trust                                        |       | 31       |
| Reporting to Unitholders                                        |       | 32       |
| Distribution Reinvestment and Optional Trust Unit Purchase Plan |       | 32       |
| CORPORATE GOVERNANCE                                            |       | 32       |
| General                                                         |       | 32       |
| Trust Indenture                                                 |       | 32       |
| Decision Making                                                 |       | 32       |
| Board of Directors of ARC Resources                             |       | 33       |
| AUDIT COMMITTEE DISCLOSURES                                     |       | 36       |
| Members of the Audit Committee                                  |       | 36       |

 

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| Principal Accountant Fees and Services                                                                  |   | 38 |
|---------------------------------------------------------------------------------------------------------|--------|----|
| CONFLICTS OF INTEREST                                                                                   |   | 38 |
| INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL  TRANSACTIONS                                             |   | 39 |
| DISTRIBUTIONS TO UNITHOLDERS                                                                            |   | 39 |
| PRICE RANGE AND TRADING VOLUME OF TRUST UNITS AND  EXCHANGEABLE SHARES                                  |   | 40 |
| INDUSTRY REGULATIONS                                                                                    |   | 40 |
| RISK FACTORS                                                                                            |   | 47 |
| Volatility of Oil and Natural Gas Prices                                                                |   | 47 |
| Reserves and Resource Estimates                                                                         |   | 48 |
| Federal Tax Changes for Income Trusts and Corporations                                                  |   | 48 |
| Operational Matters                                                                                     |   | 49 |
| Regulatory                                                                                              |   | 49 |
| Variations in Interest Rates and Foreign Exchange Rates                                                 |   | 50 |
| New Alberta Royalty Regime                                                                              |   | 50 |
| Purchase of Properties                                                                                  |   | 50 |
| Enhanced Oil Recovery                                                                                   |   | 50 |
| Project Risks                                                                                           |   | 51 |
| Changes in Legislation                                                                                  |   | 51 |
| Maintenance of Distributions                                                                            |   | 52 |
| Expansion of Operations                                                                                 |   | 52 |
| Failure to Realize Anticipated Benefits of Acquisitions and  Dispositions                               |   | 53 |
| Non-resident Ownership of Trust Units                                                                   |   | 53 |
| Environmental Concerns                                                                                  |   | 53 |
| Additional Financing                                                                                    |   | 54 |
| Competition                                                                                             |   | 54 |
| Accounting Write-Downs as a Result of GAAP                                                              |   | 55 |
| Debt Service                                                                                            |   | 55 |
| Delay in Distributions                                                                                  |   | 55 |
| Reliance on Key Members of Management                                                                   |   | 55 |
| Depletion of Reserves                                                                                   |   | 56 |
| Net Asset Value                                                                                         |   | 56 |
| Return of Capital                                                                                       |   | 56 |
| Nature of Trust Units                                                                                   |   | 56 |
| Unitholder Limited Liability                                                                            |   | 57 |
| Title to Properties                                                                                     |   | 57 |
| Additional Risk Factors Applicable to Residents of the United States  and Other Non-Residents of Canada |   | 58 |
| TRANSFER AGENTS AND REGISTRARS                                                                          |   | 59 |
| MATERIAL CONTRACTS                                                                                      |   | 59 |
| INTEREST OF EXPERTS                                                                                     |   | 59 |
| ADDITIONAL INFORMATION                                                                                  |   | 60 |

 
| APPENDIX A | - | REPORT ON RESERVES DATA BY  INDEPENDENT QUALIFIED RESERVES EVALUATOR       |
|------------|---|----------------------------------------------------------------------------|
| APPENDIX B | - | REPORT OF MANAGEMENT AND  DIRECTORS ON RESERVES DATA AND OTHER INFORMATION |
| APPENDIX C | - | MANDATE OF THE AUDIT  COMMITTEE                                            |

 

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**GLOSSARY OF TERMS**

** **

In this Annual InformationForm, capitalized terms shall have the meanings set forth below:

 

**Acquisition**means the acquisition by ARC Resources and its affiliates of three unlimitedliability corporations which together held the Acquisition Assets;

 

**AcquisitionAssets** means certain properties comprising a 45.57 percent working interest in the North Pembina Cardium Unit #1 in Alberta andthe vendors’ working interests in the Redwater area of Alberta;

 

**ARC**, **we**, **us**,**our** or **Trust** means ARC Energy Trust and all its controlled entitiesas a consolidated body;

 

**ARCResources** means ARC Resources Ltd.;

 

**ARC Sask**means ARC Oil & Gas Fund, an Alberta trust;

 

**ARC SaskReorganization** means the internal reorganization which waseffective January 1, 2008 wherein, among other things, all of ARC Sask’sassets were transferred to ARC Resources and the royalty agreements betweeneach of ARC Resources and ARC Sask and the Trust were exchanged for a newroyalty agreement between ARC Resources and the Trust;

 

**ARC Subco**means 1285637 Alberta Ltd., or such other corporation as may be substituted forARC Subco;

 

**ARML**means ARC Resources Management Ltd. a corporation that, prior to itsacquisition by ARC Resources in connection with an internalization transaction,was responsible for our management;

 

**ExchangeableShares** means the exchangeable shares of ARC Resources thatare exchangeable for Trust Units;

 

**ExchangeRatio**means the ratio at which the Exchangeable Shares maybe exchanged for Trust Units;

 

**GLJ**means GLJ Petroleum Consultants Ltd., independent petroleum consultants ofCalgary, Alberta;

 

**GLJ Report**means the report prepared by GLJ dated March 5, 2008 evaluating the crudeoil, natural gas, natural gas liquids and sulphur reserves attributable to theproperties at December 31, 2007;

 

**Long TermNotes** means the unsecured long term notes issued by ARCResources and ARC Sask to the Trust from time to time bearing interest at ratesper annum ranging from 12 per cent to 13 per cent payable monthly with maturitydates of 15 years from the date of issuance and, effective January 1, 2008means the Long Term Notes issued by ARC Resources to the Trust;

 

**Royalties**means, collectively, the royalties payable by ARC Resources and ARC Sask to theTrust pursuant to the royalty agreements which equal 99 per cent of royaltyincome and, effective January 1, 2008, means the royalty payable by ARCResources to the Trust pursuant to the royalty agreement which equals 99 percent of royalty income;

 

**Tax Act**means the *Income Tax Act*(Canada);

 

**TrustIndenture** means the trust indenture between ComputershareTrust Company of Canada, as trustee, and ARC Resources Ltd., as amended andrestated as of May 15, 2006;

 

**Trust Units**means the units of the Trust, each unit representing an equal undividedbeneficial interest in the Trust;

 

**TSX**means the Toronto Stock Exchange; and

 

**Unitholders**means holders of Trust Units of the Trust.

 

Certain other terms used inthis Annual Information Form but not defined herein are defined in NI51-101 and, unless the context otherwise requires, shall have the same meaningsherein as in NI 51-101.

 

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** **

**SPECIAL NOTES TO READER**

** **

**Regarding ForwardLooking Statements**

** **

Certain statements containedin this Annual Information Form, and in certain documents incorporated byreference into this Annual Information Form, constitute forward-lookingstatements.  These statements relate to futureevents or our future performance.  Allstatements other than statements of historical fact may be forward-lookingstatements.  Forward-looking statementsare often, but not always, identified by the use of words such as “seek”, “anticipate”,“budget”, “plan”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “project”,“predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”and similar expressions.  Thesestatements involve known and unknown risks, uncertainties and other factors thatmay cause actual results or events to differ materially from those anticipatedin such forward-looking statements.  Webelieve the expectations reflected in those forward-looking statements arereasonable but no assurance can be given that these expectations will prove tobe correct and such forward-looking statements included in, or incorporated byreference into, this Annual Information Form should not be unduly reliedupon.  These statements speak only as ofthe date of this Annual Information Form or as of the date specified inthe documents incorporated by reference into this Annual Information Form, asthe case may be.

 

In particular, this AnnualInformation Form, and the documents incorporated by reference, containforward-looking statements pertaining to the following:

 

·                                          theperformance characteristics of our oil and natural gas properties;

 

·                                          oiland natural gas production levels;

 

·                                          thesize of the oil and natural gas reserves;

 

·                                          projectionsof market prices and costs and the related sensitivities of distributions;

 

·                                          supplyand demand for oil and natural gas;

 

·                                          expectationsregarding the ability to raise capital and to continually add to reservesthrough acquisitions and development;

 

·                                          treatmentunder governmental regulatory regimes and tax laws; and

 

·                                          capitalexpenditures programs.

 

The actual results coulddiffer materially from those results anticipated in these forward-lookingstatements as a result of the risk factors set forth below and elsewhere inthis Annual Information Form:

 

·                                          volatilityin market prices for oil and natural gas;

 

·                                          liabilitiesinherent in oil and natural gas operations;

 

·                                          uncertaintiesassociated with estimating oil and natural gas reserves;

 

·                                          risksand uncertainties inherent in exploration and development activities;

 

·                                          competitionfor, among other things, capital, acquisitions of reserves, undeveloped landsand skilled personnel;

 

·                                          incorrectassessments of the value, or failure to realize the anticipated benefits, ofacquisitions;

 

·                                          geological,technical, drilling and processing problems;

 

·                                          changesin income tax laws or changes in tax or environmental laws and incentiveprograms or royalty regimes relating to the oil and gas industry and incometrusts; and

 

·                                          theother factors discussed under “*Risk Factors*”.

 

The actual results coulddiffer materially from those results anticipated in these forward-lookingstatements, which are based on assumptions, including as to the market pricesfor oil and natural gas; the continued availability of capital, acquisitions ofreserves, undeveloped lands and skilled personnel; the continuation of thecurrent tax and regulatory regime and other assumptions contained in thisAnnual Information Form.

 

Statements relating to “reserves”or “resources” are deemed to be forward-looking statements, as they involve theimplied assessment, based on certain estimates and assumptions, that theresources and reserves described can be profitably produced in the future.

 

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Readers are cautioned thatthe foregoing lists of factors are not exhaustive.  The forward-looking statements contained inthis Annual Information Form and the documents incorporated by referenceherein are expressly qualified by this cautionary statement.  We do not undertake any obligation topublicly update or revise any forward-looking statements except as required bysecurities laws or regulations.

 

**Access toDocuments**

** **

Any document referred to inthis Annual Information and described as being filed on SEDAR at www.sedar.com(including those documents referred to as being incorporated by reference inthis Annual Information Form) may be obtained free of charge from us at 2100,440 – 2nd Avenue S.W., Calgary, Alberta, T2P 5E9.

 

**Abbreviations andConversions**

 
| bbl    | Barrel                                                                                                                                     |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------|
| bbl/d  | barrels per day                                                                                                                            |
| Bcf    | billion cubic feet                                                                                                                         |
| boe    | barrels of oil equivalent converting 6 Mcf of  natural gas or one barrel of natural gas liquids to one barrel of oil  equivalent |
| boe/d  | barrels of oil equivalent per day                                                                                                     |
| Mbbl   | one thousand barrels                                                                                                                       |
| mboe   | one thousand barrels of oil equivalent                                                                                                     |
| Mcf    | one thousand cubic feet                                                                                                                    |
| Mcfpd  | one thousand cubic feet  per day                                                                                                           |
| MMBTU  | one million British  Thermal Units                                                                                                         |
| MMcf   | one million cubic feet                                                                                                                     |
| MMcfpd | one million cubic feet per  day                                                                                                            |
| $MM    | one million dollars                                                                                                                        |
| MMbbl  | one million barrels                                                                                                                        |
| NGLs   | natural gas liquids                                                                                                                        |

 

We have adopted the standardof 6 Mcf:1boe when converting natural gas to boes.  Boes may be misleading, particularly if usedin isolation.  A boe conversion ratio of6 Mcf per barrel is based on an energy equivalency conversion method primarilyapplicable at the burner tip and does not represent a value equivalency at thewellhead.

 

The following table setsforth certain standard conversions between Standard Imperial Units and theInternational System of Units (or metric units).

 

| **To Convert From** | ** ** | **To**       | ** ** | **Multiply By** | ** ** |
|---------------------|------------|--------------|------------|-----------------|------------|
| cubic metres        |       | cubic feet   |       | 35.315          |       |
| bbls                |       | cubic metres |       | 0.159           |       |
| cubic metres        |       | bbls         |       | 6.290           |       |
| Feet                |       | metres       |       | 0.305           |       |
| Metres              |       | feet         |       | 3.281           |       |
| Miles               |       | kilometres   |       | 1.609           |       |
| Kilometres          |       | miles        |       | 0.621           |       |
| Acres               |       | hectares     |       | 0.4047          |       |
| Hectares            |       | acres        |       | 2.471           |       |

 

All dollar amounts set forthin this Annual Information Form are in Canadian dollars, except whereotherwise indicated.

 

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** **

**ARC ENERGY TRUST**

** **

**General**

** **

Weare an open-end investment trust created on May 7, 1996 under the laws ofthe Province of Alberta pursuant to the Trust Indenture.  Computershare Trust Company of Canada hasbeen appointed as trustee under the Trust Indenture.  The beneficiaries of the Trust are holders ofthe Trust Units.  The principal and headoffice of the Trustee is located at Suite 600, 530 8th AvenueSW., Calgary, Alberta, T2P 3S8.  TheTrust Indenture has been amended from time to time, the latest amendments beingapproved at the annual and special meeting of Unitholders held on May 15,2006.

 

Theprincipal offices of the Trust and ARC Resources are located at 2100, 440 – 2ndAvenue S.W., Calgary, Alberta, T2P 5E9 and its registered office is located at1400, 350 – 4th Avenue S.W., Calgary, Alberta, T2P 3N9.

 

Thefollowing are the names, the percentage of voting securities and thejurisdiction governing our material****subsidiariesand trusts, either direct or indirect, as at December 31, 2007:

 
| ** **          | ** ** | **Percentage of voting  securities  (directly or indirectly)** | ** ** | **Nature of Entity** | ** ** | **Jurisdiction of  Incorporation/  Formation** | ** ** |
|---------------------|------------|------------------------------------------------------------------------------------|------------|--------------------------------|------------|-----------------------------------------------------|------------|
| ARC  Resources Ltd. |       | 100                                                                                | %          | Corporation                    |       | Alberta                                             |       |
| Orion Energy  Trust |       | 100                                                                                | %          | Trust                          |       | Alberta                                             |       |

 

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Note:
| (1) | On  January 1, 2008, all of the oil and gas assets indirectly owned by Orion  Energy Trust and directly owned by ARC Sask were transferred to ARC  Resources.  For more information, see  “Our Business – ARC Sask Reorganization”. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**General Development of Our Business**

** **

Adescription of the general development of our business over the last threefinancial years follows.

 

On June 30,2005, we acquired all of the issued and outstanding shares of RomulusExploration Inc. fortotal consideration of $42.2 million. The key property in this acquisition is directlyadjacent to ARC’s Weir Hill property in Southeast Saskatchewan.

 

On December 16, 2005, we acquired the Acquisition Assets for anaggregate purchase price of approximately $462.8 million.  In conjunction with the Acquisition, ARCResources agreed to form a reclamation trust in relation to the Redwaterproperties pursuant to which ARC Resources agreed to contribute to such trustcertain minimum amounts, totaling approximately $110 million over a 50year period, to fund future environmental and reclamation obligations inrespect of the Redwater properties, or to expend certain minimum amountstowards discharging these obligations. The amount will be contributed or expenditures incurred over such periodwith minimum annual contributions or expenditures over each of the initial fiveyears of approximately $6 million and declining thereafter.  Concurrently, we increased our creditfacility from $620 million to $950 million in order to pay for theAcquisition and on December 23, 2005 decreased our indebtedness by theamount of the net proceeds from the sale of 9,000,000 Trust Units at a price of$26.65 per Trust Unit.

 

Wecompleted property acquisitions, net of dispositions, of $115.2 million in2006.  We also completed one corporateacquisition for total consideration of $16.6 million resulting in totalacquisitions, net of dispositions, of $131.8 million in the year.

 

In2007, we completed property acquisitions, net of dispositions, of $42.5million.  We also purchased undevelopedland through crown mineral sales for $77.5 million.  The lands acquired are primarily in thegreater Dawson area of British Columbia.

 

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** **

**OUR BUSINESS**

** **

**Overview**

** **

Ourprincipal undertaking is to receive Royalties and other income on petroleum andnatural gas properties and related assets and to acquire and hold securities ofsubsidiaries, trusts and partnerships. Our subsidiaries, trusts and partnerships are entitled to carry on awide scope of energy related activities including the business of acquiring,developing, exploiting and disposing of all types of energy business relatedassets, which includes petroleum and natural gas related assets, oil sandsinterests, electricity or power generating assets and pipeline, gathering,processing and transportation assets.  Todate the Trust’s business has been focused to the acquisition and developmentof oil and natural gas reserves in Western Canada.  We issue Trust Units and may also issuesecurities of ARC Resources or an affiliate of ARC Resources which areexchangeable for Trust Units and confer voting rights in us.

 

Ourprincipal investments are the Royalties granted by ARC Resources and, prior to January 1,2008, by ARC Sask, the common shares of ARC Resources and the Long TermNotes.  The Royalties consist of a 99 percent share of royalty income on all of the properties held by ARC Resourcesand, prior to January 1, 2008, ARC Sask. Royalty income is generally all production revenue less all operatingand capital costs and all debt service charges including principalrepayments.  On each monthly distributiondate, ARC Resources and, prior to January 1, 2008, ARC Sask pay the Trust99 per cent of royalty income and ARC Resources and, prior to January 1,2008, ARC Sask pays interest on outstanding Long Term Notes.  The Trust will make distributions of suchfunds, subject only to the required deductions and its expenses.  Such distributions may be wholly or in parttaxable.  See “Distributions toUnitholders”.

 

Weare structured with the objective of having income tax incurred only in thehands of Unitholders.  Income distributedto Unitholders consists essentially of cash flow from operating activitiesgenerated by our oil and natural gas properties.  More specifically, internally generated cashflow from operating activities, with the exception of such cash flow used forcapital expenditures, reclamation fund contributions, interest expense, debtrepayments, income taxes not passed on to Unitholders, and working capitalrequirements, is effectively returned to Unitholders.

 

Asan open-ended investment, Unitholders have a right to redeem their TrustUnits.  As with most other open-endedfunds, it is anticipated that trading on the TSX and not the right ofretraction would continue as the primary mechanism for Unitholders to selltheir Trust Units.  For more detailedinformation regarding the right of redemption, see “Our Information - Right ofRedemption”.

 

Asat December 31, 2007, we had approximately 465 employees and full timeconsultants.

** **

**Federal Tax Changes for Income Trusts and Corporations**

** **

On October 31,2006, the Finance Minister announced the federal government’s plan regardingtaxation of income trusts.  Currently,distributions paid to unitholders, other than returns of capital, are claimedas a deduction by the Trust in arriving at taxable income whereby tax iseliminated at the Income Trust level and is paid by the unitholders.

 

Theincome trust tax legislation, which received Royal assent on June 22,2007, will result in a two-tiered tax structure whereby distributions wouldfirst be subject to income taxes commencing in 2011 (or earlier, if any suchincome trust exceeds the normal growth guidelines announced by the Minister on December 15,2006), and then unitholders would be subject to tax on the distribution as ifit were a taxable dividend paid by a taxable Canadian corporation (the SIFT tax”).

 

Currently,the SIFT tax rules provide that the SIFT tax rate will be the federalgeneral corporate income tax rate (which is anticipated to be 16.5 per cent in2011) plus the provincial SIFT tax factor (which is set at a fixed rate of 13per cent).

 

On December 20,2007, the Finance Minister announced technical amendments to provide someclarification to the SIFT tax legislation. As part of the announcement the Minister indicated the federalgovernment intends to provide

 

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in2008 legislation to permit income trusts to convert to taxable Canadiancorporations without any undue tax consequences to investors or the incometrust.

 

On February 26,2008, the Minister of Finance announced (the “Provincial SIFT Tax Proposal”)that instead of basing the provincial component of the SIFT tax on a flat rateof 13 per cent, the provincial component will instead be based on the generalprovincial corporate income tax rate in each province in which the income trusthas a permanent establishment.  Under theProvincial SIFT Tax Proposal the Trust would be considered to have a permanentestablishment in Alberta, where the provincial tax rate in 2011 is expected tobe 10 per cent.  There can be noassurance, however, that the Provincial SIFT Tax Proposal will be enacted asproposed.  The reduction in the generalcorporate tax rate will also apply to the taxation of income trusts, reducingthe tax rate for distributions to 28 per cent in 2012, and potentially to 25per cent if the Provincial SIFT Tax Proposal is enacted.

 

TheBoard of Directors and management of ARC continue to review the impact of thistax on our business strategy and the merits of converting to a corporation onor before January 1, 2011.  Weexpect future technical interpretations and details will further clarify thelegislation.  At the present time, ARCbelieves that if structural or other similar changes are not made, the amountof the distributions calculated on an after tax basis in 2011 to taxableCanadian investors will remain approximately the same; however, the amount ofthe distributions calculated on an after tax basis in 2011 will decline forboth tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) andforeign investors.

 

Formore information, see “Risk Factors – Federal Tax Changes for Income Trusts andCorporations” and “Risk Factors – Changes in Legislation”.

 

**Our Organizational Structure**

** **

Ourstructure and the flow of cash from ARC Resources to the Trust as of January 1,2008 are set forth below:

 

****

 

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Notes:
| (1) | As at December 31, 2007, ARC Resources was the  holder of substantially all of the properties and assets other than the  properties and assets located in Saskatchewan which were held by ARC  Sask.  Properties in British Columbia  are held by ARC Petroleum Inc. as trustee and agent of ARC Resources. |
|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2) | ARC Resources had a total of 1,309,869 Exchangeable  Shares outstanding as at December 31, 2007 that were exchangeable for  approximately 2,946,891 Trust Units.                                                                                                                                                 |

 

**ARC Sask Reorganization**

** **

Effective January 1, 2008, we completedthe ARC Sask Reorganization wherein, among other things, all of ARC Sask’sassets were transferred to ARC Resources and the royalty agreements betweeneach of ARC Resources and ARC Sask and the Trust were exchanged for a newroyalty agreement between ARC Resources and the Trust.  In addition, the obligations under the LongTerm Note from ARC Sask to the Trust were assumed by ARC Resources.

 

**Management Policies**

** **

Allour activities are directed towards maximizing distributable income toUnitholders while at the same time striving for long-term growth in the valueof our assets.  These two objectives arefundamental to our operations and are balanced to maximize benefit toUnitholders.  We direct our efforts toincrease the value of our assets through development drilling and associateddevelopment activities and enhanced oil recovery activities as well as bythe  periodic acquisition of undevelopedand producing oil and gas properties.  Weacquire oil and natural gas producing properties and primarily participate indevelopment activities that are generally considered to be of a low risk naturein the oil and gas industry.  Also, asmall percentage of each year’s capital budget will be devoted to moderate riskdevelopment and lower risk exploration opportunities on our properties.  In addition, we have undertaken a moresubstantial program of purchasing undeveloped land, particularly in thenorth-eastern British Columbia Dawson area, where we have spent approximately$100 million since 2006.

 

**Distributions and Distribution Policy**

** **

Distributionsare made on the 15th day (or if such date is not a business day, onthe next business day) following the end of each calendar month to Unitholdersof record on the last business day of each such calendar month.

 

TheBoard of Directors of ARC Resources on behalf of the Trust reviews thedistribution policy from time to time. The actual amount distributed is at the discretion of the Board ofDirectors and is principally dependent upon the commodity price environment andthe amount of cash flow from operating activities utilized to fund the Trust’scapital expenditure program and the annual contribution to the Trust’sreclamation fund.  In times of highcommodity prices, we withhold a greater percentage of cash flow from operatingactivities so that more of the capital program can be funded internally.

 

Althoughour distributions are made on a monthly basis, we normally announcedistribution levels on a quarterly basis. As we strive for stability in our distributions, any changes which mayoccur due to varying market conditions will be made with a view to maintainingthe new level of distributions for at least the next six months.

** **

See“Risk Factors – Maintenance of Distributions”.

 

**Capital Expenditures**

** **

Wemay approve future capital expenditures or farmouts under the terms of theroyalty agreement.  Future capitalexpenditures on the properties will generally be of the type that are****intended to maintain or improve productionfrom the properties.  We may financecapital expenditures from production revenues, the proceeds of the issue ofadditional Trust Units or from the proceeds of disposition of the Royaltiessold along with properties, borrowings, farmouts or with working capital.

 

Wemay acquire additional properties and related tangible equipment and fund suchacquisitions from production revenues, the net proceeds of any issue ofadditional Trust Units or from the proceeds of disposition of the Royaltiessold along with properties, or from borrowings, farmouts or with workingcapital.  We may sell any of our interestsin properties and release the Royalties from such properties in considerationof the allocation of a portion of the proceeds to the Trust, provided that thesale is approved by a special resolution of Unitholders in the event theinterests in the properties being sold constitute greater than 25 per cent ofthe asset value of all properties.  Inconnection with the sale of any interests in the properties, we will determinewhether the net proceeds of the sale 

 

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shouldbe reinvested in additional properties, used to repay borrowings or makecapital expenditures in ARC Resources or be distributed to Unitholders.

 

**Potential Acquisitions**

** **

Wecontinue to evaluate potential acquisitions of all types of petroleum andnatural gas and other energy-related assets as part of our ongoing acquisitionprogram.  We are normally in the processof evaluating several potential acquisitions at any one time which individuallyor together could be material.  We cannotpredict whether any current or future opportunities will result in one or moreacquisitions.

 

**STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION**

** **

Thestatement of reserves data and other oil and gas information is set forth below(the “Statement”).  The effective date ofthe Statement is December 31, 2007 and the preparation date of theStatement is January 28, 2008.  TheReport of Management and Directors on Reserves Data and Other Information on Form 51-101F3and the Report on Reserves Data by GLJ on Form 51-102F2 are attached asAppendices A and B to this Annual Information Form.

 

**Disclosure of Reserves Data**

** **

Thereserves data set forth below is based upon an evaluation by GLJ with aneffective date of December 31, 2007 contained in the GLJ Report dated March 5,2008.  The reserves data summarizes ouroil, liquids and natural gas reserves and the net present values of future netrevenue for these reserves using constant prices and costs and forecast pricesand costs prior to provision for interest, general and administrative expenses,the impact of any hedging activities or the liability associated with certainabandonment and well, pipeline and facilities reclamation costs which were notdeducted by GLJ in estimating future net revenue.  The evaluation does not take into account thenew Alberta royalty regime released on October 25, 2007 titled “The NewRoyalty Framework” and to be effective January 1, 2009 as sufficientdetails are not yet available for it to be taken into account.  See “Risk Factors – New Alberta RoyaltyRegime”.  Future net revenues have beenpresented on a before and after tax basis. The reserves data conforms with the requirements of NI 51-101.  We engaged GLJ to provide an evaluation ofproved and proved plus probable reserves. See also “Definitions and Notes to Reserves Data Tables” below.

 

Allof our reserves are in Canada and, specifically, in the provinces of Alberta,British Columbia, Saskatchewan and Manitoba.

 

**It should not be assumed that the estimates of future net revenuespresented in the tables below represent the fair market value of thereserves.  There is no assurance that theconstant prices and costs assumptions and forecast prices and costs assumptionswill be attained and variances could be material.  The recovery and reserves estimates of crudeoil, natural gas liquids and natural gas reserves provided herein are estimatesonly and there is no guarantee that the estimated reserves will berecovered.  Actual crude oil, natural gasand natural gas liquid reserves may be greater than or less than the estimatesprovided herein.  Readers should reviewthe definitions and information contained in “Definitions and Notes to ReservesData Tables” in conjunction with the following tables and notes.  For more information as to the risksinvolved, see “Risk Factors – Reserves Estimates” and “Risk Factors –Volatility of Oil and Natural Gas Prices”.**

 

8

----

 

**Reserves Data(Constant Prices and Costs)**

** **

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

as of December 31, 2007

CONSTANT PRICES AND COSTS

 
| ** **                  | ** ** | **RESERVES**                            | ** ** |
|-----------------------------|------------|-----------------------------------------|------------|
| ** **                  | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (Mbbl)**                       | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROVED                      |       |                                    |       |   |   |   |   |   |   |
| Developed  Producing        |       | 98,987                                  |       | 89,253 |   | 2,229 |   | 2,262 |   |
| Developed  Non-Producing    |       | 1,181                                   |       | 1,048 |   | 117 |   | 108 |   |
| Undeveloped                 |       | 11,133                                  |       | 9,550 |   | 11 |   | 11 |   |
| TOTAL PROVED                |       | 111,302                                 |       | 99,852 |   | 2,357 |   | 2,381 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROBABLE                    |       | 29,606                                  |       | 26,113 |   | 776 |   | 763 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 140,907                                 |       | 125,965 |   | 3,132 |   | 3,144 |   |

 
| ** **                  | ** ** | **RESERVES**         | ** ** |
|-----------------------------|------------|----------------------|------------|
| ** **                  | ** ** | **NATURAL GAS** | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (MMcf)**    | ** ** | **Net  (MMcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                 |       |   |   |   |   |   |   |
| PROVED                      |       |                 |       |   |   |   |   |   |   |
| Developed  Producing        |       | 437,503              |       | 371,359 |   | 9,298 |   | 6,674 |   |
| Developed  Non-Producing    |       | 28,847               |       | 22,003 |   | 486 |   | 342 |   |
| Undeveloped                 |       | 121,970              |       | 96,105 |   | 1,480 |   | 1,050 |   |
| TOTAL PROVED                |       | 588,320              |       | 489,467 |   | 11,265 |   | 8,066 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| PROBABLE                    |       | 164,953              |       | 137,751 |   | 2,971 |   | 2,174 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 753,273              |       | 627,218 |   | 14,235 |   | 10,240 |   |

 
| **RESERVES**                |
|-----------------------------|
| **TOTAL**                   | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (mboe)** | ** ** | **Net  (mboe)** | ** ** |
|                        |   |   |   |   |   |
| PROVED                      |   |   |   |   |   |
| Developed  Producing        |   | 183,431 |   | 160,083 |   |
| Developed  Non-Producing    |   | 6,592 |   | 5,165 |   |
| Undeveloped                 |   | 32,953 |   | 26,628 |   |
| TOTAL PROVED                |   | 222,977 |   | 191,876 |   |
|                        |   |   |   |   |   |
| PROBABLE                    |   | 60,844 |   | 52,009 |   |
|                        |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |   | 283,821 |   | 243,885 |   |

 

9

----

 
| ** **                   | ** ** | **NET PRESENT VALUES OF FUTURE NET REVENUE** | ** ** |
|------------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                   | ** ** | **BEFORE INCOME TAXES DISCOUNTED AT (%/year)**    | ** ** | **AFTER INCOME TAXES DISCOUNTED AT (%/year)** | ** ** |
| **RESERVES   CATEGORY** | ** ** | **0  (MM$)**                                                               | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** | **0  (MM$)** | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** |
|                         |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROVED                       |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed Producing          |       | 6,866                                                                      |       | 4,742 |   | 3,691 |   | 3,059 |   | 2,634 |   | 5,823 |   | 4,151 |   | 3,305 |   | 2,787 |   | 2,432 |   |
| Developed  Non-Producing     |       | 197                                                                        |       | 139 |   | 106 |   | 86 |   | 72 |   | 158 |   | 114 |   | 90 |   | 74 |   | 63 |   |
| Undeveloped                  |       | 888                                                                        |       | 554 |   | 373 |   | 262 |   | 189 |   | 682 |   | 428 |   | 288 |   | 200 |   | 142 |   |
| TOTAL PROVED                 |       | 7,950                                                                      |       | 5,435 |   | 4,171 |   | 3,408 |   | 2,894 |   | 6,663 |   | 4,692 |   | 3,683 |   | 3,061 |   | 2,637 |   |
|                         |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROBABLE                     |       | 2,189                                                                      |       | 1,110 |   | 689 |   | 477 |   | 354 |   | 1,613 |   | 831 |   | 523 |   | 367 |   | 275 |   |
|                         |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| TOTAL PROVED PLUS PROBABLE   |       | 10,139                                                                     |       | 6,545 |   | 4,860 |   | 3,885 |   | 3,248 |   | 8,276 |   | 5,523 |   | 4,205 |   | 3,428 |   | 2,911 |   |

 

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

as of December 31, 2007

CONSTANT PRICES AND COSTS

 
| **RESERVES  CATEGORY** | ** ** | **REVENUE   (MM$)** | ** ** | **ROYALTIES  (MM$)** | ** ** | **OPERATING  COSTS  (MM$)** | ** ** | **DEVELOPMENT  COSTS**

**(MM$)** | ** ** | **ABANDONMENT  AND  RECLAMATION   COSTS   (MM$)** | ** ** | **FUTURE  NET   REVENUE   BEFORE  INCOME  TAXES  (MM$)** | ** ** | **INCOME   TAXES  (MM$)** | ** ** | **FUTURE  NET  REVENUE  AFTER  INCOME  TAXES  (MM$)** | ** ** |
|------------------------|------------|--------------------------|------------|----------------------|------------|-----------------------------|------------|-----------------------------------|------------|-------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|--------------------------------|------------|-------------------------------------------------------|------------|
|                   |       |                     |       |                 |       |                        |       |                              |       |                                                        |       |                                                               |       |                           |       |                                                  |       |
| Proved  Reserves       |       | 14,432                   |       | 2,027                |       | 3,782                       |       | 512                               |       | 160                                                         |       | 7,950                                                              |       | 1,287                          |       | 6,663                                                 |       |
|                   |       |                     |       |                 |       |                        |       |                              |       |                                                        |       |                                                               |       |                           |       |                                                  |       |
| Proved Plus            |       |                     |       |                 |       |                        |       |                              |       |                                                        |       |                                                               |       |                           |       |                                                  |       |
| Probable               |       |                     |       |                 |       |                        |       |                              |       |                                                        |       |                                                               |       |                           |       |                                                  |       |
| Reserves               |       | 18,254                   |       | 2,615                |       | 4,593                       |       | 740                               |       | 167                                                         |       | 10,139                                                             |       | 1,863                          |       | 8,276                                                 |       |

 

FUTURE NET REVENUE

BY PRODUCTION GROUP

as of December 31, 2007

CONSTANT PRICES AND COSTS

 
| **RESERVES CATEGORY**     | ** ** | **PRODUCTION GROUP**         | ** ** | **FUTURE NET   REVENUE BEFORE   INCOME TAXES   (discounted at 10%/year)  (MM$)** | ** ** | **PER UNIT** | ** ** |
|--------------------------------|------------|-----------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|
|                           |       |                              |       |                                                                                                                     |       |              |       |   |
| Proved  Reserves               |       | Light and  Medium Crude Oil (bbl) |       | 2,988                                                                                                                    |       | $                 | 25.66      |   |
|                           |       | Heavy Oil  (bbl)                  |       | 46                                                                                                                       |       | $                 | 18.50      |   |
|                           |       | Natural  Gas(Mcf)                 |       | 1,137                                                                                                                    |       | $                 | 15.59      |   |
|                           |       | Total                             |       | 4,171                                                                                                                    |       |              |       |
|                           |       |                              |       |                                                                                                                     |       |              |       |
| Proved Plus  Probable Reserves |       | Light and  Medium Crude Oil (bbl) |       | 3,483                                                                                                                    |       | $                 | 23.81      |   |
|                           |       | Heavy Oil  (bbl)                  |       | 57                                                                                                                       |       | $                 | 17.19      |   |
|                           |       | Natural Gas  (Mcf)                |       | 1,320                                                                                                                    |       | $                 | 14.03      |   |
|                           |       | Total                             |       | 4,860                                                                                                                    |       |              |       |

 

10

----

 

**Reserves Data (Forecast Prices and Costs)**

** **

SUMMARY OF OIL AND GAS RESERVES

AND NET PRESENT VALUES OF FUTURE NET REVENUE

as of December 31, 2007

FORECAST PRICES AND COSTS

 
| ** **                  | ** ** | **RESERVES**                            | ** ** |
|-----------------------------|------------|-----------------------------------------|------------|
| ** **                  | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (Mbbl)**                       | ** ** | **Net  (Mbbl)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net  (Mbbl)** | ** ** |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROVED                      |       |                                    |       |   |   |   |   |   |   |
| Developed  Producing        |       | 98,381                                  |       | 88,697 |   | 2,224 |   | 2,258 |   |
| Developed  Non-Producing    |       | 1,174                                   |       | 1,042 |   | 117 |   | 108 |   |
| Undeveloped                 |       | 11,131                                  |       | 9,566 |   | 11 |   | 11 |   |
| TOTAL PROVED                |       | 110,686                                 |       | 99,305 |   | 2,353 |   | 2,377 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| PROBABLE                    |       | 29,698                                  |       | 26,248 |   | 782 |   | 769 |   |
|                        |       |                                    |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 140,384                                 |       | 125,553 |   | 3,134 |   | 3,146 |   |

 
| ** **                  | ** ** | **RESERVES**         | ** ** |
|-----------------------------|------------|----------------------|------------|
| ** **                  | ** ** | **NATURAL GAS** | ** ** | **NATURAL GAS LIQUIDS** | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (MMcf)**    | ** ** | **Net  (MMcf)** | ** ** | **Gross  (Mbbl)** | ** ** | **Net   (Mbbl)** | ** ** |
|                        |       |                 |       |   |   |   |   |   |   |
| PROVED                      |       |                 |       |   |   |   |   |   |   |
| Developed  Producing        |       | 438,942              |       | 372,676 |   | 9,280 |   | 6,670 |   |
| Developed  Non-Producing    |       | 28,821               |       | 21,982 |   | 486 |   | 342 |   |
| Undeveloped                 |       | 122,061              |       | 96,178 |   | 1,484 |   | 1,054 |   |
| TOTAL PROVED                |       | 589,824              |       | 490,835 |   | 11,249 |   | 8,065 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| PROBABLE                    |       | 165,058              |       | 137,885 |   | 2,969 |   | 2,176 |   |
|                        |       |                 |       |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 754,882              |       | 628,720 |   | 14,218 |   | 10,241 |   |

 
| ** **                  | ** ** | **RESERVES**      | ** ** |
|-----------------------------|------------|-------------------|------------|
| ** **                  | ** ** | **TOTAL**         | ** ** |
| **RESERVES CATEGORY**  | ** ** | **Gross  (mboe)** | ** ** | **Net  (mboe)** | ** ** |
|                        |       |              |       |   |   |
| PROVED                      |       |              |       |   |   |
| Developed  Producing        |       | 183,042           |       | 159,738 |   |
| Developed  Non-Producing    |       | 6,581             |       | 5,156 |   |
| Undeveloped                 |       | 32,970            |       | 26,661 |   |
| TOTAL PROVED                |       | 222,592           |       | 191,553 |   |
|                        |       |              |       |   |   |
| PROBABLE                    |       | 60,959            |       | 52,174 |   |
|                        |       |              |       |   |   |
| TOTAL PROVED  PLUS PROBABLE |       | 283,550           |       | 243,727 |   |

 

 

11

----

 
| ** **                   | ** ** | **NET PRESENT VALUES OF FUTURE NET REVENUE** | ** ** |
|------------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                   | ** ** | **BEFORE INCOME TAXES DISCOUNTED AT (%/year)**    | ** ** | **AFTER INCOME TAXES DISCOUNTED AT (%/year)** | ** ** |
| **RESERVES   CATEGORY** | ** ** | **0  (MM$)**                                                               | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** | **0  (MM$)** | ** ** | **5  (MM$)** | ** ** | **10  (MM$)** | ** ** | **15  (MM$)** | ** ** | **20  (MM$)** | ** ** |
|                         |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROVED                       |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Developed Producing          |       | 6,401                                                                      |       | 4,433 |   | 3,471 |   | 2,894 |   | 2,506 |   | 5,479 |   | 3,920 |   | 3,140 |   | 2,662 |   | 2,335 |   |
| Developed  Non-Producing     |       | 216                                                                        |       | 148 |   | 113 |   | 91 |   | 76 |   | 173 |   | 122 |   | 95 |   | 78 |   | 66 |   |
| Undeveloped                  |       | 946                                                                        |       | 578 |   | 384 |   | 268 |   | 192 |   | 724 |   | 445 |   | 296 |   | 205 |   | 145 |   |
| TOTAL PROVED                 |       | 7,563                                                                      |       | 5,159 |   | 3,968 |   | 3,253 |   | 2,774 |   | 6,376 |   | 4,487 |   | 3,530 |   | 2,945 |   | 2,545 |   |
|                         |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| PROBABLE                     |       | 2,428                                                                      |       | 1,146 |   | 684 |   | 464 |   | 340 |   | 1,781 |   | 855 |   | 517 |   | 355 |   | 263 |   |
|                         |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| TOTAL PROVED  PLUS PROBABLE  |       | 9,991                                                                      |       | 6,305 |   | 4,651 |   | 3,717 |   | 3,113 |   | 8,157 |   | 5,342 |   | 4,048 |   | 3,300 |   | 2,809 |   |

 

----

   Note:
| (1) | Management  has estimated that the impact of The New Royalty Framework is to decrease the  net present values of future net revenue before income taxes by approximately  2 per cent to 3 per cent using a 10 per cent discount rate and using the GLJ  forecast prices set forth in this Annual Information Form. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

TOTALFUTURE NET REVENUE

(UNDISCOUNTED)

as of December 31,2007

FORECASTPRICES AND COSTS

 
| **RESERVES  CATEGORY** | ** ** | **REVENUE **

**(MM$)** | ** ** | **ROYALTIES**

**(MM$)** | ** ** | **OPERATING**

**COSTS**

**(MM$)** | ** ** | **DEVELOPMENT  COSTS  (MM$)** | ** ** | **ABANDONMENT**

**AND**

**RECLAMATION**

**COSTS**

**(MM$)** | ** ** | **FUTURE**

**NET**

**REVENUE **

**BEFORE**

**INCOME**

**TAXES**

**(MM$)** | ** ** | **INCOME**

**TAXES**

**(MM$)** | ** ** | **FUTURE**

** NET **

**REVENUE **

**AFTER**

**INCOME**

**TAXES **

**(MM$)** | ** ** |
|------------------------|------------|------------------------------|------------|--------------------------|------------|-------------------------------------|------------|-------------------------------|------------|-----------------------------------------------------------------|------------|--------------------------------------------------------------------------------------|------------|----------------------------------|------------|-------------------------------------------------------------------------------------------------------|------------|
|                   |       |                         |       |                     |       |                                |       |                          |       |                                                            |       |                                                                                 |       |                             |       |                                                                                                  |       |
| Proved  Reserves       |       | 15,444                       |       | 2,138                    |       | 4,956                               |       | 549                           |       | 238                                                             |       | 7,563                                                                                |       | 1,187                            |       | 6,376                                                                                                 |       |
|                   |       |                         |       |                     |       |                                |       |                          |       |                                                            |       |                                                                                 |       |                             |       |                                                                                                  |       |
| Proved Plus            |       |                         |       |                     |       |                                |       |                          |       |                                                            |       |                                                                                 |       |                             |       |                                                                                                  |       |
| Probable               |       |                         |       |                     |       |                                |       |                          |       |                                                            |       |                                                                                 |       |                             |       |                                                                                                  |       |
| Reserves               |       | 20,124                       |       | 2,821                    |       | 6,248                               |       | 793                           |       | 271                                                             |       | 9,991                                                                                |       | 1,834                            |       | 8,157                                                                                                 |       |

 

12

----

 

FUTURENET REVENUE

BYPRODUCTION GROUP

as of December 31,2007

FORECASTPRICES AND COSTS

 
| **RESERVES CATEGORY**     | ** ** | **PRODUCTION GROUP**         | ** ** | **FUTURE NET**

**REVENUE **

**BEFORE **

**INCOME TAXES**

**(discounted at**

**10%/year)**

**(MM$)** | ** ** | **PER UNIT** | ** ** |
|--------------------------------|------------|-----------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|
|                           |       |                              |       |                                                                                                                               |       |              |       |   |
| Proved  Reserves               |       | Light and  Medium Crude Oil (bbl) |       | 2,605                                                                                                                              |       | $                 | 22.48      |   |
|                           |       | Heavy Oil  (bbl)                  |       | 56                                                                                                                                 |       | $                 | 22.54      |   |
|                           |       | Natural Gas  (Mcf)                |       | 1,307                                                                                                                              |       | $                 | 17.85      |   |
|                           |       | Total                             |       | 3,968                                                                                                                              |       |              |       |
|                           |       |                              |       |                                                                                                                               |       |              |       |
| Proved Plus  Probable Reserves |       | Light and  Medium Crude Oil (bbl) |       | 3,049                                                                                                                              |       | $                 | 20.90      |   |
|                           |       | Heavy Oil  (bbl)                  |       | 69                                                                                                                                 |       | $                 | 20.91      |   |
|                           |       | Natural Gas  (Mcf)                |       | 1,534                                                                                                                              |       | $                 | 16.25      |   |
|                           |       | Total                             |       | 4,651                                                                                                                              |       |              |       |

 

----

Note:
| (1) | Management  has estimated that the impact of The New Royalty Framework is to decrease the  net present values of future net revenue before income taxes by approximately  2 per cent to 3 per cent using a 10 per cent discount rate and using the GLJ  forecast prices set forth in this Annual Information Form. |
|-----|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**Definitions and Notes to Reserves Data Tables:**

** **

Inthe tables set forth above in “Disclosure of Reserves Data” and elsewhere inthis Annual Information Form the following definitions and other notes areapplicable:

 

1.                                       “**Gross**” means:

 

(a)                                  in relation to our interest in production and reserves, our interest(operating and non-operating) before deduction of royalties and withoutincluding any royalty interest of us;

 

(b)                                 in relation to wells, the total number of wells in which we have aninterest; and

 

(c)                                  in relation to properties, the total area of properties in which wehave an interest.

 

2.                                       “**Net**” means:

 

(a)                                  in relation to our interest in production and reserves, our interest(operating and non-operating) after deduction of royalties obligations, plusour royalty interest in production or reserves;

 

(b)                                 in relation to wells, the number of wells obtained by aggregatingour working interest in each of our gross wells; and

 

(c)                                  in relation to our interest in a property, the total area in whichwe have an interest multiplied by the working interest we owned.

 

3.                                       Columns may not add due to rounding.

 

4.                                       The crude oil, natural gas liquids and natural gas reservesestimates presented in the GLJ Report are based on the definitions andguidelines contained in the Canadian Oil and Gas Evaluation Handbook (COGEHandbook).  A summary of thosedefinitions are set forth below:

 

13

----

 

**ReservesCategories**

 

Reserves are estimatedremaining quantities of oil and natural gas and related substances anticipatedto be recoverable from known accumulations, from a given date forward, based onanalysis of drilling, geological, geophysical and engineering data; the use ofestablished technology; and specified economic conditions.

 

Reserves are classifiedaccording to the degree of certainty associated with the estimates.

 

(a)                                  **Proved reserves**are thosereserves that can be estimated with a high degree of certainty to berecoverable. It is likely that the actual remaining quantities recovered willexceed the estimated proved reserves.

 

(b)                                 **Probable reserves** arethose additional reserves that are less certain to be recovered than provedreserves. It is equally likely that the actual remaining quantities recoveredwill be greater or less than the sum of the estimated proved plus probablereserves.

 

Other criteria that must alsobe met for the categorization of reserves are provided in the COGE Handbook.

 

Each of the reserves categories(proved and probable) may be divided into developed and undeveloped categories:

 

(c)                                  **Developed reserves** are those reserves that are expected to be recovered from existingwells and installed facilities or, if facilities have not been installed, thatwould involve a low expenditure (for example, when compared to the cost ofdrilling a well) to put the reserves on production. The developed category maybe subdivided into producing and non-producing.

 

(i)            **Developed producing reserves** are thosereserves that are expected to be recovered from completion intervals open atthe time of the estimate. These reserves may be currently producing or, ifshut-in, they must have previously been on production, and the date ofresumption of production must be known with reasonable certainty.

 

(ii)           **Developednon-producing reserves** are those reserves thateither have not been on production, or have previously been on production, butare shut-in, and the date of resumption of production is unknown.

 

(d)                                 **Undeveloped reserves** are those reserves expected to be recovered from knownaccumulations where a significant expenditure (for example, when compared tothe cost of drilling a well) is required to render them capable of production.They must fully meet the requirements of the reserves classification (proved,probable) to which they are assigned.

 

In multi-well pools it may beappropriate to allocate total pool reserves between the developed andundeveloped categories or to subdivide the developed reserves for the poolbetween developed producing and developed non-producing. This allocation shouldbe based on the estimator’s assessment as to the reserves that will berecovered from specific wells, facilities and completion intervals in the pooland their respective development and production status.

 

**Levels ofCertainty for Reported Reserves**

 

The qualitative certaintylevels referred to in the definitions above are applicable to individualreserves entities (which refers to the lowest level at which reservescalculations are performed) and to reported reserves (which refers to thehighest level sum of individual entity estimates for which reserves arepresented). Reported reserves should target the following levels of certaintyunder a specific set of economic conditions:

 

(a)           at least a 90 per centprobability that the quantities actually recovered will equal or exceed theestimated proved reserves; and

 

14

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(b)                                 at least a 50 per cent probability that the quantities actuallyrecovered will equal or exceed the sum of the estimated proved plus probablereserves.

 

A qualitative measure of thecertainty levels pertaining to estimates prepared for the various reservescategories is desirable to provide a clearer understanding of the associatedrisks and uncertainties. However, the majority of reserves estimates will beprepared using deterministic methods that do not provide a mathematicallyderived quantitative measure of probability. In principle, there should be nodifference between estimates prepared using probabilistic or deterministicmethods.

 

Additional clarification ofcertainty levels associated with reserves estimates and the effect ofaggregation is provided in the COGE Handbook.

 

5.                                       Forecast prices and costs

 

These are prices and costs thatare generally acceptable as being a reasonable outlook of the future.  To the extent that there are fixed orpresently determinable future prices or costs to which we are legally bound bya contractual or other obligation to supply a physical product, including thosefor an extension period of a contract that is likely to be extended, thoseprices or costs shall be incorporated into the forecast prices.

 

The forecast cost and priceassumptions include increases in wellhead selling prices and take into accountinflation with respect to future operating and capital costs.  Crude oil, natural gas and natural gasliquids benchmark reference pricing, as at January 1, 2008, inflation andexchange rates utilized in the GLJ Report were as follows:

 

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONSas of December 31, 2007FORECAST PRICES AND COSTS

 
| ** ** | ** ** | **OIL**                                   | ** ** | **NATURAL**                                       | ** ** | **EDMONTON LIQUIDS PRICES**    | ** ** | ** **                                  | ** ** | ** **                             | ** ** |
|------------|------------|-------------------------------------------|------------|---------------------------------------------------|------------|------------------------------------------|------------|---------------------------------------------|------------|----------------------------------------|------------|
| ** ** | ** ** | ** **                                | ** ** | **Edmonton**                                      | ** ** | **Hardisty**                             | ** ** | **Cromer**                                  | ** ** | **GAS**                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Year**   | ** ** | **WTI Cushing  Oklahoma  ($US/bbl)** | ** ** | **Par Price  40° API  ($Cdn/bbl)** | ** ** | **Heavy  12° API  ($Cdn/bbl)** | ** ** | **Medium  29.3° API  ($Cdn/bbl)** | ** ** | **AECO Gas  Price  ($Cdn/MMbtu)** | ** ** | **Propane  ($Cdn/bbl)** | ** ** | **Butane  ($Cdn/bbl)** | ** ** | **Pentanes  Plus  ($Cdn/bbl)** | ** ** | **INFLATION  RATES(1)  %/Year** | ** ** | **EXCHANGE  RATE(2)  ($US/$Cdn)** | ** ** |
|       |       |                                      |       |                                              |       |                                     |       |                                        |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
| Forecast   |       |                                      |       |                                              |       |                                     |       |                                        |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
| 2008       |       | 92.00                                     |       | 91.10                                             |       | 54.02                                    |       | 79.26                                       |       | 6.75                                   |       | 58.30 |   | 72.88 |   | 92.92 |   | 2 | % | 1.00 |   |
| 2009       |       | 88.00                                     |       | 87.10                                             |       | 51.61                                    |       | 75.78                                       |       | 7.55                                   |       | 55.74 |   | 69.68 |   | 88.84 |   | 2 | % | 1.00 |   |
| 2010       |       | 84.00                                     |       | 83.10                                             |       | 49.19                                    |       | 72.30                                       |       | 7.60                                   |       | 53.18 |   | 66.48 |   | 84.76 |   | 2 | % | 1.00 |   |
| 2011       |       | 82.00                                     |       | 81.10                                             |       | 47.98                                    |       | 70.56                                       |       | 7.60                                   |       | 51.90 |   | 64.88 |   | 82.72 |   | 2 | % | 1.00 |   |
| 2012       |       | 82.00                                     |       | 81.10                                             |       | 47.98                                    |       | 70.56                                       |       | 7.60                                   |       | 51.90 |   | 64.88 |   | 82.72 |   | 2 | % | 1.00 |   |
| 2013       |       | 82.00                                     |       | 81.10                                             |       | 49.04                                    |       | 70.56                                       |       | 7.60                                   |       | 51.90 |   | 64.88 |   | 82.72 |   | 2 | % | 1.00 |   |
| 2014       |       | 82.00                                     |       | 81.10                                             |       | 50.09                                    |       | 70.56                                       |       | 7.80                                   |       | 51.90 |   | 64.88 |   | 82.72 |   | 2 | % | 1.00 |   |
| 2015       |       | 82.00                                     |       | 81.10                                             |       | 51.15                                    |       | 70.56                                       |       | 7.97                                   |       | 51.90 |   | 64.88 |   | 82.72 |   | 2 | % | 1.00 |   |
| 2016       |       | 82.02                                     |       | 81.12                                             |       | 52.21                                    |       | 70.57                                       |       | 8.14                                   |       | 51.91 |   | 64.89 |   | 82.74 |   | 2 | % | 1.00 |   |
| 2017       |       | 83.66                                     |       | 82.76                                             |       | 53.29                                    |       | 72.00                                       |       | 8.31                                   |       | 52.97 |   | 66.21 |   | 84.42 |   | 2 | % | 1.00 |   |
| Thereafter |       | (3)                             |       | (3)                                     |       | (3)                            |       | (3)                               |       | (3)                          |       | (3)   |   | (3)   |   | (3)   |   | 2 | % | 1.00 |   |

 

----

Notes:

(1)                                  Inflation rates forforecasting prices and costs.

(2)                                  Exchange rates used togenerate the benchmark reference prices in this table.

(3)                                  Prices escalate 2.0 per centper year from 2018.

 

Weighted average actual pricesrealized for the year ended December 31, 2007, were $6.75/Mcf for naturalgas, $70.20/bbl for light and medium crude oil, $49.17/bbl for heavy crude oiland $54.79/bbl for natural gas liquids. Only a minor amount of our production is characterized as heavy oil

 

15

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6.                                       Constant prices and costs

 

These are actual prices andcosts as at the effective date of the estimation, held constant throughout theestimated lives of the properties to which the estimate applies.  To the extent that there are fixed orpresently determinable future prices or costs to which we are legally bound bya contractual or other obligation to supply a physical product, including thosefor an extension period of a contract that is likely to be extended, thoseprices or costs shall be incorporated into the price for future years.

 

The constant crude oil andnatural gas benchmark reference pricing and the exchange rate utilized in theGLJ Report were as follows:

 

SUMMARY OF PRICING ASSUMPTIONSas of December 31, 2007CONSTANT PRICES AND COSTS

 
| **OIL**                          | ** ** | ** **                                        | ** ** | **EDMONTON LIQUID PRICES**        | ** ** | ** **                                  | ** ** |
|----------------------------------|------------|---------------------------------------------------|------------|---------------------------------------------|------------|---------------------------------------------|------------|
| **WTI**                          | ** ** | **Edmonton**                                      | ** ** | **LLB Crude**                          | ** ** | **Cromer**                                  | ** ** | **NATURAL** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Cushing  Oklahoma  ($US/bbl)** | ** ** | **Par Price  40° API  ($Cdn/bbl)** | ** ** | **Oil at   Hardisty  ($Cdn/bbl)** | ** ** | **Medium  29.3° API  ($Cdn/bbl)** | ** ** | **GAS  AECO Gas Price  ($Cdn/MMBTU)** | ** ** | **Propane  ($Cdn/bbl)** | ** ** | **Butane  ($Cdn/bbl)** | ** ** | **Pentanes  Plus  ($Cdn/bbl)** | ** ** | **EXCHANGE  RATE(1)  ($US/$Cdn)** | ** ** |
|                             |       |                                              |       |                                        |       |                                        |       |   |   |   |   |   |   |   |   |   |   |
| 95.95                            |       | 93.39                                             |       | 53.74                                       |       | 94.24                                       |       | 6.63 |   | 59.77 |   | 74.71 |   | 94.24 |   | 1.012 |   |

 

----

Note:

(1)                                  The exchange rate used togenerate the benchmark reference prices in this table.

 

7.                                       Future Development Costs

 

The following table sets forthdevelopment costs deducted in the estimation of our future net revenueattributable to the reserves categories noted below.

 
| ** **                     | ** ** | **Forecast Prices and Costs** | ** ** |
|--------------------------------|------------|----------------------------------------------|------------|
| **Year**                       | ** ** | **Proved Reserves  (MM****$****)**      | ** ** | **Proved Plus Probable  Reserves (MM****$****)** | ** ** |
|                           |       |                                         |       |   |   |
| 2008                           |       | 191                                          |       | 224 |   |
| 2009                           |       | 142                                          |       | 193 |   |
| 2010                           |       | 78                                           |       | 115 |   |
| 2011                           |       | 18                                           |       | 74 |   |
| 2012                           |       | 13                                           |       | 29 |   |
| Total:  Undiscounted           |       | 549                                          |       | 793 |   |
| Total:  Discounted at 10%/year |       | 417                                          |       | 593 |   |

 

We expect to fund thedevelopment costs of the reserves through a combination of cash flow fromoperating activities, debt, the sale of existing assets and the issuance ofTrust Units.

 

There can be no guarantee thatfunds will be available or that we will allocate funding to develop all of thereserves attributed in the GLJ Report. Failure to develop those reserves would have a negative impact on futurecash flow from operating activities.

 

The interest or other costs ofexternal funding are not included in the reserves and future net revenueestimates and would reduce reserves and future net revenue to some degreedepending upon the funding sources utilized. We do not anticipate that interest or other funding costs would makedevelopment of any property uneconomic.

 

8.                                       Estimated future well abandonment costs related to reserves wellshave been taken into account by GLJ in determining the aggregate future netrevenue therefrom.

 

16

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9.                                       Both the constant and forecast price and cost assumptions assumedthe continuance of current laws and regulations.

 

10.                                 All factual data supplied to GLJ was accepted as represented.  No field inspection was conducted.

 

11.                                 **The estimates of future net revenue presented in thetables above do not represent fair market value.**

 

**Reconciliationsof Changes in Reserves**

** **

The following table sets forth thereconciliation of our gross reserves as at December 31, 2007, usingforecast price and cost estimates derived from the GLJ Report.  Gross reserves as at December 31, 2007and as at December 31, 2006 include working interest reserves beforeroyalties payable and without including gross royalties receivable.

 

RECONCILIATION OFGROSS RESERVESBY PRINCIPAL PRODUCT TYPEFORECAST****PRICES AND COSTS

 
| ** **              | ** ** | **LIGHT AND MEDIUM OIL** | ** ** | **HEAVY OIL**   | ** ** | **NATURAL GAS**               | ** ** |
|-------------------------|------------|-----------------------------------------|------------|----------------------|------------|------------------------------------|------------|
| **FACTORS**             | ** ** | **Proved  (Mbbl)**                      | ** ** | **Probable  (Mbbl)** | ** ** | **Proved  Plus  Probable  (Mbbl)** | ** ** | **Proved  (Mbbl)** | ** ** | **Probable  (Mbbl)** | ** ** | **Proved  Plus  Probable  (Mbbl)** | ** ** | **Proved  (Bcf)** | ** ** | **Probable  (Bcf)** | ** ** | **Proved  Plus  Probable  (Bcf)** | ** ** |
|                    |       |                                    |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31,  2006 |       | 112,647                                 |       | 30,936               |       | 143,583                            |       | 2,517 |   | 844 |   | 3,361 |   | 581.6 |   | 147.6 |   | 729.2 |   |
|                    |       |                                    |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Discoveries             |       | 0                                       |       | 0                    |       | 0                                  |       | 0 |   | 0 |   | 0 |   | 0.9 |   | 0.2 |   | 1.1 |   |
| Extensions              |       | 370                                     |       | 388                  |       | 758                                |       | 129 |   | 92 |   | 221 |   | 15.2 |   | 5.7 |   | 20.9 |   |
| Improved  Recovery      |       | 1,896                                   |       | 413                  |       | 2,309                              |       | 16 |   | -16 |   | 0 |   | 1.7 |   | 0.4 |   | 2.1 |   |
| Infill Drilling         |       | 2,298                                   |       | 510                  |       | 2,808                              |       | 0 |   | 0 |   | 0 |   | 22.8 |   | 7.9 |   | 30.7 |   |
| Technical  Revisions    |       | 1,473                                   |       | -2,373               |       | -900                               |       | -19 |   | -141 |   | -160 |   | 29.2 |   | 3.0 |   | 32.3 |   |
| Acquisitions            |       | 1,002                                   |       | 243                  |       | 1,245                              |       | 0 |   | 0 |   | 0 |   | 3.0 |   | 0.9 |   | 3.9 |   |
| Dispositions            |       | -162                                    |       | -23                  |       | -185                               |       | 0 |   | 0 |   | 0 |   | -0.4 |   | -0.1 |   | -0.4 |   |
| Economic  Factors       |       | 1,126                                   |       | -396                 |       | 730                                |       | 49 |   | 2 |   | 51 |   | -0.9 |   | -0.5 |   | -1.4 |   |
| Production              |       | -9,964                                  |       | 0                    |       | -9,964                             |       | -339 |   | 0 |   | -339 |   | -63.4 |   | 0.0 |   | -63.4 |   |
|                    |       |                                    |       |                 |       |                               |       |   |   |   |   |   |   |   |   |   |   |   |   |
| December 31,  2007 |       | 110,686                                 |       | 29,698               |       | 140,384                            |       | 2,353 |   | 782 |   | 3,134 |   | 589.8 |   | 165.1 |   | 754.9 |   |

 
| ** **              | ** ** | **NATURAL GAS LIQUIDS** | ** ** | **TOTAL**            | ** ** |
|-------------------------|------------|-----------------------------------|------------|----------------------|------------|
| **FACTORS**             | ** ** | **Proved  (Mbbl)**                | ** ** | **Probable  (Mbbl)** | ** ** | **Proved  Plus  Probable  (Mbbl)** | ** ** | **Proved  (mboe)** | ** ** | **Probable  (mboe)** | ** ** | **Proved  Plus  Probable  (mboe)** | ** ** |
|                    |       |                              |       |                 |       |   |   |   |   |   |   |   |   |
| December 31,  2006 |       | 11,768                            |       | 3,002                |       | 14,770 |   | 223,869 |   | 59,378 |   | 283,248 |   |
|                    |       |                              |       |                 |       |   |   |   |   |   |   |   |   |
| Discoveries             |       | 5                                 |       | 1                    |       | 7 |   | 156 |   | 31 |   | 187 |   |
| Extensions              |       | 112                               |       | 33                   |       | 145 |   | 3,142 |   | 1,465 |   | 4,607 |   |
| Improved  Recovery      |       | 56                                |       | 13                   |       | 69 |   | 2,254 |   | 468 |   | 2,722 |   |
| Infill  Drilling        |       | 322                               |       | 43                   |       | 365 |   | 6,421 |   | 1,874 |   | 8,294 |   |
| Technical  Revisions    |       | 339                               |       | -120                 |       | 219 |   | 6,665 |   | -2,128 |   | 4,537 |   |
| Acquisitions            |       | 96                                |       | 14                   |       | 111 |   | 1,598 |   | 401 |   | 1,999 |   |
| Dispositions            |       | -24                               |       | -5                   |       | -30 |   | -245 |   | -41 |   | -285 |   |
| Economic  Factors       |       | 25                                |       | -12                  |       | 13 |   | 1,043 |   | -490 |   | 553 |   |
| Production              |       | -1,450                            |       | 0                    |       | -1,450 |   | -22,312 |   | 0 |   | -22,312 |   |
|                    |       |                              |       |                 |       |   |   |   |   |   |   |   |   |
| December 31,  2007 |       | 11,249                            |       | 2,969                |       | 14,218 |   | 222,592 |   | 60,958 |   | 283,550 |   |

 

17

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**AdditionalInformation Relating to Reserves Data**

** **

***Proved and Probable Undeveloped Reserves***

*** ***

Undeveloped reserves are attributed by GLJ inaccordance with standards and procedures contained in the COGE Handbook.  Proved undeveloped reserves are thosereserves that can be estimated with a high degree of certainty and are expectedto be recovered from known accumulations where a significant expenditure isrequired to render them capable of production. Probable undeveloped reserves are those reserves that are less certainto be recovered than proved reserves and are expected to be recovered fromknown accumulations where a significant expenditure is required to render themcapable of production.

 

The following table discloses by each producttype separately the volumes of proved undeveloped reserves and probableundeveloped reserves reflected in the GLJ Report in aggregate prior to 2005 andfirst attributed in each of the three years thereafter along with the aggregateof such reserves on each of December 31, 2005, 2006 and 2007.

 

**Timing of InitialUndeveloped Reserves Assignment**

 
| ** **                   | ** ** | ** ** | ** ** | **Company Gross Reserves First Attributed By Year** | ** ** |
|------------------------------|------------|------------|------------|-----------------------------------------------------------------------------------|------------|
| **Product Type**        | ** ** | **Units**  | ** ** | **Prior**                                                                         | ** ** | **2005** | ** ** | **2006** | ** ** | **2007** | ** ** | **Total** | ** ** |
| ***Proved Undeveloped***     |       |       |       |                                                                              |       |   |   |   |   |   |   |   |   |
| *** ***                 |       |       |       |                                                                              |       |   |   |   |   |   |   |   |   |
| Light &  Medium Oil |       | Mbbl       |       | 3,577                                                                             |       | 2,983 |   | 2,170 |   | 2,401 |   | 11,131 |   |
| Heavy Oil                    |       | Mbbl       |       | 0                                                                                 |       | 0 |   | 0 |   | 11 |   | 11 |   |
| Natural Gas                  |       | MMcf       |       | 34,517                                                                            |       | 17,577 |   | 29,866 |   | 40,101 |   | 122,061 |   |
| Natural Gas  Liquids         |       | Mbbl       |       | 525                                                                               |       | 290 |   | 434 |   | 235 |   | 1,484 |   |
| **Total:  Oil Equivalent**   | ** ** | **Mboe**   | ** ** | **9,855**                                                                         | ** ** | **6,203** | ** ** | **7,582** | ** ** | **9,330** | ** ** | **32,969** | ** ** |
| ** **                   | ** ** | ** ** | ** ** | ** **                                                                        | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ***Probable Undeveloped***   |       |       |       |                                                                              |       |   |   |   |   |   |   |   |   |
| *** ***                 |       |       |       |                                                                              |       |   |   |   |   |   |   |   |   |
| Light &  Medium Oil |       | Mbbl       |       | 3,233                                                                             |       | 1,294 |   | 3,698 |   | 1,832 |   | 10,057 |   |
| Heavy Oil                    |       | Mbbl       |       | 0                                                                                 |       | 98 |   | 0 |   | 113 |   | 211 |   |
| Natural Gas                  |       | MMcf       |       | 39,092                                                                            |       | 2,430 |   | 3,782 |   | 22,534 |   | 67,837 |   |
| Natural Gas  Liquids         |       | Mbbl       |       | 454                                                                               |       | 102 |   | 300 |   | 178 |   | 1,034 |   |
| **Total:  Oil Equivalent**   | ** ** | **Mboe**   | ** ** | **10,202**                                                                        | ** ** | **1,900** | ** ** | **4,628** | ** ** | **5,879** | ** ** | **22,608** | ** ** |

 

Approximately 70% of the proved plus probableundeveloped reserves are located in the Dawson, Ante Creek, Weyburn and shallowgas properties.  In each case, we areengaged in a program for the development of a portion of the undevelopedreserves in 2008.  For furtherinformation, see “Additional Information Relating to Reserve Data – Explorationand Development Activities”.

 

In some cases it will take us longer than twoyears to develop these reserves.  We planto develop the majority of the proved undeveloped reserves in the reservesevaluation over the next four years and plan to develop the probable undevelopedreserves over the next five years.

 

We manage development activities to ensurefacilities and gathering systems are properly utilized over the facility lifewhich means scheduling capital over a longer period.  We develop assets in a methodical fashion toreduce risk by technically assessing the results of one annual drilling programbefore embarking on another drilling program.

 

***Significant Factors or Uncertainties***

 

We have a significant amount of provedundeveloped reserves assigned to the Dawson gas field in northeast BritishColumbia and the Hatton/Horsham gas fields in southwest Saskatchewan.  Sophisticated and expensive technology isrequired for the Dawson wells to produce. At the current prices, these wells are economic; however, should gasprices fall materially, the wells may not be economic to drill.  Similarly, the low rate gas wells insouthwest Saskatchewan may also be uneconomic in a low price environment.

 

18

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**OtherOil and Gas Information**

 

Our portfolio of properties asat December 31, 2007 includes both unitized and non-unitized oil andnatural gas production.  In general, theproperties contain long life, low decline rate reserves and include interestsin several major oil and gas fields.

*** ***

***Principal Properties***

*** ***

The following is a descriptionof our principal oil and natural gas properties as at December 31,2007.  Reserves amounts are stated at December 31,2007, based on escalated cost and price assumptions as evaluated in the GLJReport prepared by GLJ (see “Statement of Reserves Data and Other Oil and GasInformation”).  Information in respect ofgross and net acres and well counts are as at December 31, 2007, andinformation in respect of production is for the year ended December 31,2007 except where indicated otherwise. Due to the fact that we have been active at acquiring additionalinterests in our principal properties, the working interest share and interestin gross and net acres and wells as at December 31, 2007 may not directlycorrespond to the stated production for the year which only includes productionsince the date the interests were acquired by us.  The estimates of reserves and future netrevenue for individual properties may not reflect the same confidence level asestimates of reserves and future net revenue for all properties, due to theeffects of aggregation.

 

All of the properties describedbelow are located in the Western Canadian Sedimentary Basin and within theCanadian provinces of British Columbia, Alberta or Saskatchewan.  The properties represent 57 per cent of thetotal gross proved plus probable reserves as assigned by GLJ in the GLJReport.  There are no other propertieswhich individually account for more than 3.3 per cent of the total gross provedplus probable reserves as assigned by GLJ in the GLJ Report.  There are no material properties to whichreserves have been attributed which are capable of producing but which are notproducing and there are no material statutory or mandatory relinquishments,surrenders, back-ins or changes in ownership provisions.

 
| ** **                 | ** ** | **Gross Reserves and Gross Production** | ** ** |
|----------------------------|------------|-------------------------------------------------------------|------------|
| ** **                 | ** ** | **2007  Production**                                        | ** ** | **Proved  Reserves** | ** ** | **Proved plus Probable Reserves** | ** ** |
| ** **                 | ** ** | **(boe/d)**                                                 | ** ** | **(mboe)** | ** ** | **(mboe)** | ** ** | **(%)** | ** ** |
|                       |       |                                                        |       |   |   |   |   |   |   |
| Dawson                     |       | 4,657                                                       |       | 22,369 |   | 30,154 |   | 10.6 |   |
| Ante Creek                 |       | 4,618                                                       |       | 20,484 |   | 26,198 |   | 9.2 |   |
| Redwater                   |       | 3,998                                                       |       | 22,341 |   | 26,028 |   | 9.2 |   |
| Lougheed                   |       | 2,779                                                       |       | 6,699 |   | 8,358 |   | 2.9 |   |
| Jenner                     |       | 2,627                                                       |       | 11,049 |   | 14,128 |   | 5.0 |   |
| Hatton                     |       | 2,317                                                       |       | 8,449 |   | 9,882 |   | 3.5 |   |
| Weyburn Unit               |       | 1,969                                                       |       | 10,249 |   | 15,635 |   | 5.5 |   |
| Pouce Coupe                |       | 1,840                                                       |       | 3,947 |   | 4,878 |   | 1.7 |   |
| North Pembina Cardium Unit |       | 1,772                                                       |       | 13,251 |   | 15,382 |   | 5.4 |   |
| Berrymoor Cardium Unit     |       | 1,535                                                       |       | 9,014 |   | 11,104 |   | 3.9 |   |

 

***Dawson***

*** ***

The Dawson property is located in northeastBritish Columbia. We are the operator and own an average land interest of 92per cent. We operate a large area compression facility where the natural gasand liquids are sent to a third party operated facility. During 2007, grossproduction from the area averaged 4,657 boe/d of natural gas and natural gasliquids from 74 net wells. During 2007, 13 new wells were drilled. GLJ assignedgross proved reserves of 22,369 mboe and gross proved plus probable reserves of30,154 mboe of natural gas and natural gas liquids to this area, or 10.6 percent of total gross proved plus probable reserves.

 

***Ante Creek***

*** ***

The Ante Creek property is located innorthwest Alberta. We are the operator and own an average land interest of 93per cent. Oil production is processed through three operated facilities, whilethe gas is processed through one operated facility and one third partyfacility. During 2007, gross production from the area averaged 4,618 boe/d of 

 

19

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oil, natural gas and natural gas liquids from165 net wells. During 2007, 12 new wells were drilled. GLJ assigned grossproved reserves of 20,484 mboe and gross proved plus probable reserves of26,198 mboe of oil, natural gas and natural gas liquids to this area, or 9.2per cent of total gross proved plus probable reserves.

 

***Redwater***

*** ***

The Redwater property is located in centralAlberta. We are the operator and own an average land interest of 86 per cent.Oil and solution gas are both processed at an operated central facility. During2007, gross production from the area averaged 3,998 boe/d of oil, natural gas andnatural gas liquids from 395 net wells. During 2007, 13 new wells were drilled.GLJ assigned gross proved reserves of 22,341 mboe and gross proved plusprobable reserves of 26,028 mboe of oil, natural gas and natural gas liquids tothis area, or 9.2 per cent of total gross proved plus probable reserves.

 

***Lougheed***

*** ***

The Lougheed property is located in southeastSaskatchewan. We are the operator and own an average land interest of 79 percent. Production is handled by an operated battery and gas plant. During 2007,gross production from the area averaged 2,779 boe/d of oil and natural gasliquids from 121 net wells. During 2007, 12 new wells were drilled. GLJassigned gross proved reserves of 6,699 mboe and gross proved plus probablereserves of 8,358 mboe of oil and natural gas liquids to this area, or 2.9 percent of total gross proved plus probable reserves.

 

***Jenner***

*** ***

The Jenner property is located in southeastAlberta. We own a combination of operated and non-operated acreage with anaverage land interest of 88 per cent. We operate four gas compression anddehydration facilities in the area. During 2007, gross production from the areaaveraged 2,627 boe/d of natural gas from 832 net wells. During 2007, 64 newwells were drilled. GLJ assigned gross proved reserves of 11,049 mboe and grossproved plus probable reserves of 14,128 mboe of natural gas to this area, or5.0 per cent of total gross proved plus probable reserves.

 

***Hatton***

*** ***

The Hatton property is located in southwestSaskatchewan. We own a combination of operated and non-operated acreage with anaverage land interest of 44 per cent. The operated production flows throughthree operated compression and dehydration facilities where our workinginterest ranges from 50 to 100 per cent. During 2007, gross production from thearea averaged 2,317 boe/d of natural gas from 434 net wells. During 2007, twonew wells were drilled. GLJ assigned gross proved reserves of 8,449 mboe andgross proved plus probable reserves of 9,882 mboe of natural gas to this area,or 3.5 per cent of total gross proved plus probable reserves.

 

***Weyburn Unit***

*** ***

The Weyburn unit is located in southeastSaskatchewan. EnCana Corporation operates the unit and we have a workinginterest of 6.95 per cent. The unit is currently undergoing a CO2 flood forenhanced oil recovery. During 2007 gross production from the unit averaged1,969 boe/d of oil from 52 net wells. During 2007, 45 new wells were drilled.GLJ assigned gross proved reserves of 10,249 mboe and gross proved plusprobable reserves of 15,635 mboe of oil and natural gas liquids to this unit,or 5.5 per cent of total gross proved plus probable reserves.

 

***Pouce Coupe***

*** ***

The Pouce Coupe property is located innorthwest Alberta. We are the operator and own an average land interest of 73per cent. The sweet gas is processed through an operated gas plant and the sourgas flows to a third party processing plant. During 2007, gross production fromthe area averaged 1,840 boe/d of oil, natural gas and natural gas liquids from39 net wells. During 2007, seven wells were drilled. GLJ assigned gross provedreserves of 3,947 mboe and gross proved plus probable reserves of 4,878 mboe ofoil, natural gas and natural gas liquids to this area, or 1.7 per cent of totalgross proved plus probable reserves.

 

20

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***North Pembina Cardium Unit***

*** ***

The North Pembina Cardium Unit No. 1 islocated in central Alberta. We are the operator and own a 45.57 per centinterest in the unit. Production is processed through two operated oiltreatment facilities and one operated solution gas plant. During 2007, grossproduction from the unit averaged 1,772 boe/d of oil, natural gas and naturalgas liquids from 174 net wells. During 2007, 14 new wells were drilled. GLJassigned gross proved reserves of 13,251 mboe and gross proved plus probablereserves of 15,382 mboe of oil, natural gas and natural gas liquids to thisunit, or 5.4 per cent of total gross proved plus probable reserves.

 

***Berrymoor Cardium Unit***

*** ***

The Berrymoor Cardium Unit is located incentral Alberta. We are the operator and own a 73.25 per cent interest in theunit. Oil is processed at an operated battery while the solution gas flows to athird party facility.  During 2007, grossproduction from the unit averaged 1,535 boe/d of oil, natural gas and naturalgas liquids from 85 net wells. During 2007, six new wells were drilled. GLJassigned gross proved reserves of 9,014 mboe and gross proved plus probablereserves of 11,104 mboe of oil, natural gas and natural gas liquids to thisunit, or 3.9 per cent of total gross proved plus probable reserves.

 

***Oil And Gas Wells***

*** ***

The following table sets forth the number andstatus of wells in which we had a working interest as at December 31,2007.

 
| ** **        | ** ** | **Oil Wells** | ** ** | **Natural Gas Wells** | ** ** |
|-------------------|------------|--------------------|------------|---------------------------------|------------|
| ** **        | ** ** | **Producing**      | ** ** | **Non-Producing**               | ** ** | **Producing** | ** ** | **Non-Producing** | ** ** |
| ** **        | ** ** | **Gross**          | ** ** | **Net**                         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|              |       |               |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Alberta           |       | 4,153              |       | 1,565                           |       | 1,040 |   | 141 |   | 4,275 |   | 1,865 |   | 206 |   | 37 |   |
| British  Columbia |       | 8                  |       | 2                               |       | 4 |   | 2 |   | 243 |   | 80 |   | 39 |   | 15 |   |
| Saskatchewan      |       | 2,099              |       | 788                             |       | 269 |   | 87 |   | 5,401 |   | 846 |   | 57 |   | 22 |   |
| Manitoba          |       | 550                |       | 121                             |       | 23 |   | 4 |   | — |   | — |   | — |   | — |   |
| Total             |       | 6,810              |       | 2,476                           |       | 1,336 |   | 234 |   | 9,919 |   | 2,791 |   | 302 |   | 75 |   |

*** ***

***Properties with no Attributable Reserves***

*** ***

The following table sets out our undevelopedland holdings as at December 31, 2007.

 
| ** **             | ** ** | **Undeveloped Acres** | ** ** |
|------------------------|------------|----------------------------|------------|
| ** **             | ** ** | **Gross**                  | ** ** | **Net** | ** ** |
|                   |       |                       |       |   |   |
| Alberta                |       | 661,878                    |       | 281,130 |   |
| British  Columbia      |       | 163,049                    |       | 112,583 |   |
| Manitoba               |       | 1,675                      |       | 954 |   |
| Northwest  Territories |       | 224,675                    |       | 2,087 |   |
| Saskatchewan           |       | 294,866                    |       | 139,478 |   |
| Total                  |       | 1,346,143                  |       | 536,232 |   |

 

Of the undeveloped acres in British Columbia,we have 73,019 gross acres and 67,424 net acres in the greater Dawson areawhich have varying degrees of prospectivity in the Montney zones.  For more information on our exploration anddevelopment plans, see “Additional Information Relating to Reserve Data –Exploration and Development Activities”.

 

We currently have no material workcommitments on these lands.  We expectthat approximately 55,328 net acres of our undeveloped land holdings willexpire by December 31, 2008.

 

21

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***ForwardContracts***

*** ***

We areexposed to market risks resulting from fluctuations in commodity prices,foreign exchange rates and interest rates in the normal course ofoperations.  A variety of derivativeinstruments are used to reduce our exposure to fluctuations in commodityprices, foreign exchange rates and interest rates.  We are also exposed to losses in the event ofdefault by the counterparties to these derivative instruments.  We manage this risk by diversifying ourderivative portfolio among a number of financially sound counterparties.  For information in relation to marketingarrangements, see “Other Oil and Gas Information – Marketing Arrangements”.

 

We have a hedging program under whichfinancial and physical hedges can be entered into in respect of commodityprices and foreign currency exchange rates. The program permits hedging to a maximum of 55 per cent of forecastedTrust production on a boe basis for up to 24 months and up to 15 per cent on aboe basis for the 36 month period thereafter (years three to five in thefuture). ** **The program allows the sale of upsideparticipation only to the extent of 25 per cent of forecasted volumes beyond athree month period at a price which is at least 20 per cent above the forwardprice and 50 per cent of forecasted volumes within a three month period at aprice which is at least 10 per cent above the forward price.  The program also allows flexibility to hedgeup to 70 per cent of either natural gas or oil in meeting the overall hedginglimit of 50 per cent of the Trust’s forecasted production on a boe basis.  These policies are continuously reviewed bymanagement and the Board.  The Board hasrecently appointed a  Risk Committee withone of its objectives being to review our financial and business risks includingour hedging program.

 

Asummary of financial and physical contracts in respect of hedging activitiescan be found in Note 11 “Financial Instruments” to our auditedconsolidated financial statements for the year ended December 31, 2007 andin the section under the heading “Risk Management and Hedging” in ourmanagement discussion and analysis and results of operations for the year endedDecember 31, 2007 which have been filed on SEDAR at www.sedar.com, andboth of which note and section are incorporated in this Annual Information Form byreference.

 

***AdditionalInformation Concerning Abandonment and Reclamation Costs***

*** ***

The followingtable sets forth information respecting future abandonment and reclamationcosts for surface leases, wells, facilities and pipelines which we expect toincur for the periods indicated.

 
| ** **                          | ** ** | **Abandonment and Reclamation  Costs escalated at 2.0%  Undiscounted  ($MM)** | ** ** | **Abandonment and Reclamation  Costs escalated at 2.0%  Discounted at 10%  ($MM)** | ** ** |
|-------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------|------------|
| Total as at  December 31, 2007 |       | 1,289.6                                                                                           |       | 70.2                                                                                                             |       |
| Anticipated  to be paid in 2008     |       | 4.7                                                                                               |       | 4.3                                                                                                              |       |
| Anticipated  to be paid in 2009     |       | 4.9                                                                                               |       | 4.0                                                                                                              |       |
| Anticipated  to be paid in 2010     |       | 5.0                                                                                               |       | 3.7                                                                                                              |       |

 

We will beliable for our share of ongoing environmental obligations and for the ultimatereclamation of the properties held by us upon abandonment.  We estimate that we have 6,318 net wellswhich are subject to environmental reclamation obligations.  Ongoing environmental obligations are expectedto be funded out of cash flow from operating activities and any balanceavailable in our reclamation fund.

 

We have areclamation fund to pay future asset retirement obligations costs.  We currently estimate that the futureenvironmental and reclamation obligations in respect of our properties will beapproximately $1,290 million calculated by escalating costs at two per cent peryear (reflected in the 2007 audited financials statements as an assetretirement obligation of $140.0 million calculated by escalating costs at twoper cent per year and discounting at a blended rate of 6.6 per cent).  For more information, see Note 10 of ouraudited 2007 financial statements and the section in our management’sdiscussion and analysis of operations of such financial statements under theheading “Asset Retirement Obligation and Reclamation Fund”, which note andsection are incorporated in this Annual Information Form by reference andare found on SEDAR at www.sedar.com.  TheBoard of Directors of ARC Resources has approved voluntary contributions to ourreclamation fund over a twenty year period that results in minimum annualcontributions of $6.0 million ($6.0 million in 2007) based on properties ownedas at December 31, 2007.  During2007, $17.5 million ($5.7 million for 2006) of actual expenditures were chargedagainst the 

 

22

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reclamation fund resulting in a net reductionof our reclamation fund for the year of $10.4 million ($1.3 million netaddition in 2006).

 

In additionthe Trust has committed to a restricted reclamation trust associated with theRedwater property acquired in the Acquisition pursuant to which ARC Resourceshas agreed to contribute to such trust certain minimum amounts, totallingapproximately $110 million over a 50 year period, to fund future environmentaland reclamation obligations in respect of the Redwater properties, or to expendcertain minimum amounts towards discharging these obligations. The restrictedcontribution commenced in 2007 for $6.0 million and continues at a decliningrate through 2055. The current balance of this trust as of December 31,2007 is $11.7 million.

 

We estimatethe costs to abandon and reclaim all our shut in and producing wells,facilities, gas plants, pipelines, batteries and satellites.  No estimate of salvage value is netted againstthe estimated cost.  Our model forestimating the amount and timing of future abandonment and reclamationexpenditures was created on an operating area level.  Estimated expenditures for each operatingarea are based on the Alberta Energy Utilities Board methodology which detailsthe cost of abandonment and reclamation in eight specific geographicregions.  Each region was assigned anaverage cost per well to abandon and reclaim the wells in that area.

 

Abandonmentand reclamation costs have been estimated over a 50 year period.  Facility reclamation costs are scheduled tobe incurred in the year following the end of the reserves life of itsassociated reserve.

 

The additionalliability associated with well, pipelines and facilities reclamation costs whichwere not deducted by GLJ in estimating future net revenue in the GLJ Report are$1,052 million (escalating costs at two per cent and undiscounted) and $19.2million (escalating costs at two per cent and discounted at 10 per cent).  Only the abandonment costs associated withwells with reserves were deducted by GLJ in estimating future net revenue.

 

***Tax Horizon***

*** ***

As a result ofour tax efficient structure, annual taxable income is currently transferredfrom our operating entities to the Trust and from the Trust toUnitholders.  This is primarilyaccomplished through the deduction by our operating entities of the Royaltieson underlying oil and gas properties and the deduction of interest on the LongTerm Notes.

 

On October 31,2006, the Government of Canada announced tax proposals pertaining to taxationof distributions paid by trusts.  Theseproposals were passed into law on June 22, 2007 and will result in atwo-tiered tax structure whereby distributions would first be subject to thefederal corporate income tax rate plus a deemed Provincial income tax at thetrust level commencing in 2011 (or earlier, if trusts that were publicly tradedas of October 31, 2006 exceed the normal growth guidelines announced bythe Government of Canada on December 15, 2006), and then investors wouldbe subject to tax on the distribution as if it were a taxable dividend paid bya taxable Canadian corporation.

 

The effect ofthis new legislation is reflected in the after tax net revenue amountsdisclosed in the Reserves Data (Forecast Prices and Costs) in this AnnualInformation Form, other than the recently announced Provincial SIFT TaxProposal.  See “Our Business – FederalTax Changes for Income Trusts and Corporations”.

 

The trust taxrate applicable to 2007 is 34.0 per cent, however, the application of the trusttax should be deferred until 2011 as the Trust has not exceeded the normalgrowth guidelines.  Absent the trust tax,it can be expected that minimal income taxes would be incurred by the Trust orits operating entities provided we maintain this organizational taxstructure.  However, annual operatingincome retained to pay a portion of capital expenditures or used to repay debtmay result in income tax liabilities within ARC Resources from time totime.  See “Risk Factors – Federal TaxChanges for Income Trusts and Corporations” and “Risk Factors – Changes inLegislation”.

 

***CapitalExpenditures***

*** ***

The followingtables summarize capital expenditures (net of incentives and net of certainproceeds and including capitalized general and administrative expenses) relatedto our activities for the year ended December 31, 2007:

 

23

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| ** **                     | ** ** | **2007  $MM** | ** ** |
|--------------------------------|------------|---------------|------------|
| Property  acquisition costs(1) |       |          |       |
| Proved  properties             |       | 33.1          |       |
| Undeveloped  properties        |       | 9.4           |       |
| Exploration  costs(2)          |       | 112.5         |       |
| Development  costs(3)          |       | 281.4         |       |
| Corporate  capital costs       |       | 3.3           |       |
| Total                          |       | 439.7         |       |

 

----

Notes:

(1)                                  Represents acquisition costsnet of dispositions and property swaps.

(2)                                  Costs of land acquired,geological and geophysical capital expenditures and drilling costs for 2007exploration wells drilled.

(3)                                  Development and facilitiescapital expenditures.

 

***Explorationand Development Activities***

*** ***

The followingtable sets forth the gross and net exploratory and development wells that we participatedin during the year ended December 31, 2007:

 
| ** **            | ** ** | **Exploratory Wells** | ** ** | **Development Wells** | ** ** | **Total** | ** ** |
|-----------------------|------------|----------------------------|------------|----------------------------|------------|-----------|------------|
| ** **            | ** ** | **Gross**                  | ** ** | **Net**                    | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Light and  Medium Oil |       | 9                          |       | 5.9                        |       | 176       |       | 75.0 |   | 185 |   | 80.9 |   |
| Heavy Oil             |       | —                     |       | —                     |       | 5         |       | 0.0 |   | 5 |   | 0.0 |   |
| Natural Gas           |       | 30                         |       | 13.0                       |       | 340       |       | 162.5 |   | 370 |   | 175.5 |   |
| Service               |       | —                     |       | —                     |       | 10        |       | 2.3 |   | 10 |   | 2.3 |   |
| Dry                   |       | 15                         |       | 5.6                        |       | 9         |       | 3.1 |   | 24 |   | 8.8 |   |
| Total:                |       | 54                         |       | 24.5                       |       | 540       |       | 242.9 |   | 594 |   | 267.5 |   |

 

We have anextensive capital program of $395 million planned for 2008. The primarycomponents of our program are as follows.

 

Our planned$83 million program in Dawson includes the drilling of 12 vertical and eighthorizontal development, exploration and delineation wells. In addition todrilling activities, capital will also be devoted to expanding the existinginfrastructure.

 

In AnteCreek, our planned $36 million capital program includes the drilling of eightdevelopment wells, one exploration well and three horizontal injection wells toexpand the existing waterflood area.

 

InDelburne, we plan to drill 55 shallow wells and install new facilities andcompression as part of the natural gas from coal program. The area capitalis $18 million.

 

In theHatton, Horsham and Brooks areas of southeast Alberta and southwestSaskatchewan, we plan to drill 111 gross shallow gas wells and perform variousoptimization projects at a cost of $34 million.

 

Ourcapital program is subject to variation throughout the year and there is noassurance that all or any part of our capital program will be expended as setforth above.  In addition, capitalexpenditures may be made on the acquisition of undeveloped land or oil andnatural gas reserves.

 

See “RiskFactors – Operational Matters” and “Risk Factors – Project Risks”.

 

***ProductionEstimates***

*** ***

The followingtable sets out the volume of our production estimated for the year ended December 31,2008 which is reflected in the estimate of gross proved reserves and grossprobable reserves disclosed in the tables contained under “Statement ofReserves Data and Other Oil and Gas Information - Disclosure of ReservesData”.

 

24

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| ** **                  | ** ** | **Light and  Medium Oil** | ** ** | **Heavy Oil** | ** ** | **Natural Gas** | ** ** | **Natural Gas  Liquids** | ** ** | **Total**   | ** ** |
|-----------------------------|------------|-------------------------------------|------------|--------------------|------------|----------------------|------------|-------------------------------|------------|-------------|------------|
| ** **                  | ** ** | **(bbl/d)**                         | ** ** | **(bbl/d)**        | ** ** | **(Mcfpd)**          | ** ** | **(bbl/d)**                   | ** ** | **(boe/d)** | ** ** |
| ** **                  | ** ** | **Gross**                           | ** ** | **Net**            | ** ** | **Gross**            | ** ** | **Net**                       | ** ** | **Gross**   | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Total Proved                |       | 26,593                              |       | 22,833             |       | 911                  |       | 906                           |       | 182,213     |       | 146,572 |   | 3,783 |   | 2,705 |   | 61,656 |   | 50,873 |   |
| Total Proved  Plus Probable |       | 27,657                              |       | 23,688             |       | 974                  |       | 964                           |       | 186,515     |       | 149,793 |   | 3,886 |   | 2,778 |   | 63,603 |   | 52,396 |   |

*** ***

***ProductionHistory***

*** ***

The followingtables summarize certain information in respect of our production, productprices received, royalties paid, operating expenses and resulting netback forthe periods indicated below:

 
| ** **                                               | ** ** | **Quarter Ended  2007** | ** ** | **Year Ended** | ** ** |
|----------------------------------------------------------|------------|------------------------------|------------|---------------------|------------|
| **(6:1)**                                                | ** ** | **Mar. 31**             | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **2007** | ** ** |
| Average  Daily Production(1)                             |       |                         |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil (bbl/d)                      |       | 28,094                       |       | 26,767              |       | 27,207 |   | 27,402 |   | 27,366 |   |
| Heavy Oil  (bbl/d)                                       |       | 1,426                        |       | 1,333               |       | 1,230 |   | 1,279 |   | 1,316 |   |
| Gas (MMcfpd)                                             |       | 183.0                        |       | 176.7               |       | 173.3 |   | 187.4 |   | 180.1 |   |
| NGLs (bbl/d)                                             |       | 4,161                        |       | 4,088               |       | 3,795 |   | 4,067 |   | 4,027 |   |
| Combined  (boe/d)                                        |       | 64,175                       |       | 61,637              |       | 61,108 |   | 63,989 |   | 62,723 |   |
|                                                     |       |                         |       |                |       |   |   |   |   |   |   |
| Average Net  Production Prices Received                  |       |                         |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)                      |       | 61.71                        |       | 66.09               |       | 74.40 |   | 78.54 |   | 70.20 |   |
| Heavy Oil  ($/bbl)                                       |       | 42.81                        |       | 47.50               |       | 51.23 |   | 55.85 |   | 49.17 |   |
| Gas ($/Mcf)                                              |       | 7.75                         |       | 7.38                |       | 5.52 |   | 6.32 |   | 6.75 |   |
| NGLs ($/bbl)                                             |       | 48.04                        |       | 52.76               |       | 55.64 |   | 62.75 |   | 54.79 |   |
| Combined  ($/boe)                                        |       | 53.29                        |       | 54.48               |       | 53.41 |   | 57.42 |   | 54.67 |   |
|                                                     |       |                         |       |                |       |   |   |   |   |   |   |
| Royalties  Paid                                          |       |                         |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)                      |       | 9.58                         |       | 10.48               |       | 11.75 |   | 13.69 |   | 11.33 |   |
| Heavy Oil  ($/bbl)                                       |       | 3.57                         |       | 4.11                |       | 4.35 |   | 5.39 |   | 4.34 |   |
| Gas ($/Mcf)                                              |       | 1.60                         |       | 1.34                |       | 0.87 |   | 1.16 |   | 1.25 |   |
| NGLs ($/bbl)                                             |       | 12.57                        |       | 14.43               |       | 15.44 |   | 17.21 |   | 14.90 |   |
| Combined  ($/boe)                                        |       | 9.65                         |       | 9.43                |       | 8.76 |   | 10.46 |   | 9.59 |   |
|                                                     |       |                         |       |                |       |   |   |   |   |   |   |
| Operating  Expenses (2)(3)                               |       |                         |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)                      |       | 10.85                        |       | 12.19               |       | 12.32 |   | 12.13 |   | 11.84 |   |
| Heavy Oil  ($/bbl)                                       |       | 11.07                        |       | 15.47               |       | 11.85 |   | 10.30 |   | 12.16 |   |
| Gas ($/Mcf)                                              |       | 1.20                         |       | 1.22                |       | 1.30 |   | 1.28 |   | 1.26 |   |
| NGLs ($/bbl)                                             |       | 8.83                         |       | 7.76                |       | 8.19 |   | 7.82 |   | 7.73 |   |
| Combined  ($/boe)                                        |       | 8.99                         |       | 9.63                |       | 9.93 |   | 9.64 |   | 9.54 |   |
|                                                     |       |                         |       |                |       |   |   |   |   |   |   |
| Transportation  Paid                                     |       |                         |       |                |       |   |   |   |   |   |   |
| Light and Medium  Crude Oil ($/bbl)                      |       | 0.48                         |       | 0.34                |       | 0.10 |   | 0.18 |   | 0.27 |   |
| Heavy Oil  ($/bbl)                                       |       | 1.50                         |       | 0.93                |       | 1.1 |   | 0.69 |   | 1.09 |   |
| Gas ($/Mcf)                                              |       | 0.20                         |       | 0.19                |       | 0.20 |   | 0.20 |   | 0.20 |   |
| NGLs ($/bbl)                                             |       | 0.00                         |       | 0.00                |       | 0.00 |   | 0.00 |   | 0.00 |   |
| Combined  ($/boe)                                        |       | 0.81                         |       | 0.72                |       | 0.65 |   | 0.69 |   | 0.72 |   |
|                                                     |       |                         |       |                |       |   |   |   |   |   |   |
| (Gain)/Loss  on Commodity and Foreign Exchange Contracts |       |                         |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)                      |       | 1.26                         |       | 1.04                |       | (0.28 | ) | (2.38 | ) | (0.07 | ) |
| Heavy Oil  ($/bbl)                                       |       | 0.00                         |       | 0.00                |       | 0.00 |   | 0.00 |   | 0.00 |   |
| Gas ($/Mcf)                                              |       | 0.23                         |       | (0.14               | )          | 0.56 |   | 0.29 |   | 0.23 |   |
| NGLs ($/bbl)                                             |       | 0.00                         |       | 0.00                |       | 0.00 |   | 0.00 |   | 0.00 |   |
| Combined  ($/boe)                                        |       | 1.21                         |       | 0.05                |       | 1.45 |   | (0.20 | ) | 0.62 |   |

 

25

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| ** **                             | ** ** | **Quarter Ended  2007** | ** ** | **Year Ended** | ** ** |
|----------------------------------------|------------|------------------------------|------------|---------------------|------------|
| **(6:1)**                              | ** ** | **Mar. 31**             | ** ** | **June 30**    | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** | **2007** | ** ** |
| Netback  Received(4)                   |       |                         |       |                |       |   |   |   |   |   |   |
| Light and  Medium Crude Oil ($/bbl)(5) |       | 42.06                        |       | 44.12               |       | 49.95 |   | 50.15 |   | 46.69 |   |
| Heavy Oil  ($/bbl)                     |       | 26.67                        |       | 26.99               |       | 33.82 |   | 39.48 |   | 31.58 |   |
| Gas ($/Mcf)                            |       | 4.98                         |       | 4.49                |       | 3.71 |   | 3.97 |   | 4.27 |   |
| NGLs ($/bbl)                           |       | 26.64                        |       | 30.57               |       | 32.01 |   | 37.73 |   | 32.16 |   |
| Combined  ($/boe)                      |       | 35.05                        |       | 34.75               |       | 35.52 |   | 36.42 |   | 35.44 |   |

 

----

Notes:

(1)                                  Before deduction of royalties.

(2)                                  Operating expenses arecomposed of direct costs incurred to operate both oil and gas wells.  A number of assumptions have been made inallocating these costs between oil, natural gas and natural gas liquidsproduction.

(3)                                  Operating recoveriesassociated with operated properties were excluded from operating costs andaccounted for as a reduction to general and administrative costs.

(4)                                  Netbacks are calculated bysubtracting royalties, operating costs, transportation costs, and losses/gainson commodity and foreign exchange contracts from revenues.

(5)                                  Heavy oil net backs have beenincluded in light/medium oil netbacks, as only a minor amount of our productioncomes from heavy oil.

 

No propertyaccounts for more than 7.4 per cent of the production disclosed above.  For more information, see “Other Oil and GasInformation – Principal Properties”.

 

**Marketing Arrangements**

** **

***Natural Gas***

*** ***

During 2007,we continued our marketing strategy of increasing the level of direct controland diversification of marketing and transportation arrangements for ournatural gas production.

 

The averagenatural gas price we received during 2007 was $6.75 per Mcf as compared to$6.97 per Mcf for 2006.  This price wasachieved with a portfolio mix that on average through the year received AECOindex based pricing for 66 per cent, aggregator netback prices for 23 per cent,and Chicago Index Pricing for 11 per cent of total production.

 

To managenatural gas price volatility and to stabilize the revenue stream, our naturalgas portfolio is directed towards maintaining balanced exposure to U.S. andCanadian markets with market sensitive and hedgeable pricing terms, as well asaggregator netback arrangements.  We alsostrive for a high utilization of contracted pipeline and processing capacity.

 

***Crude Oil andNatural Gas Liquids***

*** ***

Our liquidsproduction in 2007 was comprised of approximately 51 per cent light qualitycrude oil (greater than 35°API), 32 per cent medium quality crude oil (25 to 35API), 4 per cent heavy quality crude (less than 25°API), 5 per cent condensateand 8 per cent natural gas liquids. During 2007, our average sales prices were $70.77 per bbl for light andmedium crude oil, $50.55 per bbl for heavy crude oil and $54.79 per bbl fornatural gas liquids; these prices compare to 2006 prices of $66.16 per bbl forlight and medium crude oil, $46.90 per bbl for heavy crude oil and $52.63 perbbl for natural gas liquids.  Our crudeoil is sold under contracts of varying terms of up to one year, based on marketsensitive pricing terms.  Natural gasliquids are sold under annual arrangements. Industry pricing benchmarks for crude oil and natural gas liquids arecontinuously monitored to ensure optimal netbacks.

 

**Acquisitions and Dispositions**

** **

We completedproperty acquisitions, net of dispositions, of $42.5 million in 2007.

 

26

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**SHARE CAPITAL OF ARC RESOURCES**

** **

**Common Shares**

** **

ARC Resourceshas authorized for issuance an unlimited number of common shares of which1,000,111 common shares are issued and outstanding and held by theTrust.  The voting of such shares isdelegated to ARC Resources under the Trust Indenture.  The holders of common shares are entitled tonotice of, to attend and to one vote per share held at any meeting of theshareholders of ARC Resources; to receive dividends as and when declared byBoard of Directors of ARC Resources on the common shares as a class, andsubject to prior satisfaction of all preferential rights to dividends attachedto all shares of other classes; and in the event of any liquidation,dissolution or winding-up of ARC Resources, whether voluntary or involuntary,or any other distribution of the assets of ARC Resources among its shareholdersfor the purpose of winding-up its affairs, and subject to prior satisfaction ofall preferential rights to return of capital on dissolution attached to allshares of other classes of shares of ARC Resources ranking in priority to thecommon shares in respect of return of capital on dissolution, to sharerateably, together with the shares of any other class of shares of ARCResources ranking equally with the common shares in respect of return ofcapital on dissolution, in such assets of ARC Resources as are available fordistribution.

 

**Exchangeable Shares**

** **

ARC Resourcesis authorized to issue an unlimited number of Exchangeable Shares of which, asat December 31, 2007, 1,309,869 were outstanding.  The Exchangeable Shares rank prior to thecommon shares of ARC Resources, the second preferred shares of ARC Resourcesand any other shares ranking junior to the Exchangeable Shares with respect tothe payment of dividends and the distribution of assets in the event of theliquidation, dissolution or winding-up of ARC Resources; provided thatnotwithstanding such ranking ARC Resources shall not be restricted in any wayfrom repaying indebtedness of ARC Resources to the Trust from time totime.  The Exchangeable Share provisionshave been filed on SEDAR at www.sedar.com.

 

TheExchangeable Shares provide holders with a security having economic, ownershipand voting rights which are substantially equivalent to those of TrustUnits.  As at December 31, 2007 theExchange Ratio was 2.24976 Trust Units per Exchangeable Share.  Holders of Exchangeable Shares will notreceive distributions, rather the Exchangeable Shares are maintainedeconomically equivalent to the Trust Units by the progressive increase in theExchange Ratio to reflect distributions paid by the Trust to Unitholders.  The Exchangeable Shares are providedequivalent voting rights as those of Unitholders through an agreement (theExchangeable Share Voting and Exchange Trust Agreement) pursuant to which theholders of Exchangeable Shares can direct the Trustee to vote at meetings ofUnitholders.  The holders of ExchangeableShares are further assured of the delivery of Trust Units by us in satisfactionof the obligations of ARC Resources under the Exchangeable Share terms throughthe provisions of another agreement (the Exchangeable Share SupportAgreement).  Copies of the ExchangeableShare Voting and Exchange Trust Agreement and the Exchangeable Share SupportAgreement have been filed on SEDAR at www.sedar.com.

 

ComputershareTrust Company of Canada acts as the transfer agent for the Exchangeable Shares.

 

Holders ofExchangeable Shares are entitled to receive, as and when declared by the Boardof Directors in its sole discretion, from time to time, cumulative preferentialcash dividends in an amount per share equal to the Exchange Ratio on thepreceding business day multiplied by the fair market value of a Trust Unit asat the preceding business day (determined on the basis of the weighted averageprice of the Trust Unit on the TSX for the 10 trading days preceding thatdate).  It is not anticipated thatdividends will be declared or paid on the Exchangeable Shares, however theBoard of Directors has the right in its sole discretion to do so, and if so,the Exchange Ratio would be reduced accordingly to reflect such dividends.

 

ARC Resourceswill not, without obtaining the approval of the holders of the ExchangeableShares:

 

(a)                                  pay any dividend on the common shares of ARC Resources, secondpreferred shares of ARC Resources or any other shares ranking junior to theExchangeable Shares, other than the stock dividends payable in common shares ofARC Resources or any such other shares ranking junior to the ExchangeableShares;

 

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(b)                                 redeem, purchase or make any capital distribution in respect of thecommon shares of ARC Resources, second preferred shares of ARC Resources or anyother shares ranking junior to the Exchangeable Shares;

 

(c)                                  redeem or purchase any other shares of ARC Resources ranking equallywith respect to the payment of dividends or on any liquidation distribution; or

 

(d)                                 issue any shares, other than Exchangeable Shares, second preferredshares of ARC Resources or common shares of ARC Resources, which rank superiorto the Exchangeable Shares with respect to the payment of dividends or on anyliquidation distribution.

 

Notwithstandingthe foregoing, the restrictions in paragraphs (a), (b) and (c) aboveshall only be applicable if dividends which have been declared on theoutstanding Exchangeable Shares have not been paid in full.

 

TheExchangeable Share Provisions entitle the holder to exchange each ExchangeableShare at any time into the number of Trust Units equal to the Exchange Ratiothen in effect.  The Exchange Ratio isdetermined by reference to the distributions paid on Trust Units in a givenmonth and the current market price of the Trust Units.

 

**Second Preferred Shares**

** **

ARC Resourcesalso has authorized an unlimited number of Second Preferred Shares which may atany time or from time to time be issued in one or more series.  Before any shares of a particular series areissued, the Board of Directors of ARC Resources shall, by resolution, fix thenumber of shares that will form such series and shall, subject to thelimitations set out herein, by resolution fix the designation, rights,privileges, restrictions and conditions to be attached to the Second PreferredShares of such series.  The SecondPreferred Shares of each series shall rank behind the Exchangeable Shares andon a parity with the Second Preferred Shares of every other series with respectto accumulated dividends and return of capital. The Second Preferred Shares are entitled to a preference over the CommonShares and over any other shares of ARC Resources ranking junior to the SecondPreferred Shares with respect to priority in the payment of dividends and inthe distribution of assets in the event of the liquidation, dissolution orwinding-up of ARC Resources, whether voluntary or involuntary, or any otherdistribution of the assets of ARC Resources among its shareholders for the purpose of winding-up itsaffairs.  As at the date hereof, thereare Second Preferred Share, Series 1 and Second Preferred Share, Series 2issued and outstanding which were issued to ARC Sask in consideration of thetransfer of properties pursuant to the ARC Sask Reorganization and which areredeemable by ARC Resources for $1,000 per share, together with all accrued andunpaid dividends.

 

**OTHER INFORMATION RELATING TO OUR BUSINESS**

** **

**Borrowing**

** **

We borrowfunds from time to time to finance the purchase of properties, for capitalexpenditures or for other financial obligations or expenditures in respect ofproperties held by us or for working capital purposes.  We have a policy relating to borrowing whichrequires a quarterly assessment by management, subject to review by the Boardof Directors of ARC Resources, of the appropriateness of borrowing levels.  We have granted security in priority to theRoyalties to secure the loan of such funds.

 

Debt servicecharges on borrowed funds attributable to our properties, including fundsborrowed by our subsidiaries from us, will be deducted in computing royaltyincome. The debt repayment will be scheduled to minimize any income tax payableby ARC Resources.

 

At December 31,2007 we had a $800 million secured, extendible, financial covenant based threeyear syndicated credit facility that expires in April 2010 and a $25million demand working capital facility in addition to US $218 million ofsenior secured notes outstanding.  Thecredit facilities and senior secured notes contain provisions which restrictthe ability of ARC Resources to pay Royalties and interest under the Long TermNotes to us and thereby may restrict distributions to Unitholders, in the eventof the occurrence of certain events of default. The credit agreement and note agreements are described under “MaterialContracts” and have been filed on SEDAR at www.sedar.com.  For more information, reference is made tonote 9 of our audited consolidated financial statements 

 

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for the yearended December 31, 2007, which is incorporated by reference in this AnnualInformation Form and which has been filed on SEDAR at www.sedar.com.

 

See “RiskFactors – Additional Financing” and “Risk Factors – Variations in InterestRates and Foreign Exchange Rates”.

 

**OUR INFORMATION**

** **

**Trust Units**

** **

A maximum of650,000,000 Trust Units have been created and may be issued pursuant to theTrust Indenture.  The Trust Unitsrepresent equal undivided beneficial interests in the Trust. All Trust Unitsshare equally in all distributions made by us and all Trust Units carry equal votingrights at meetings of Unitholders.  NoUnitholder will be liable to pay any further calls or assessments in respect ofthe Trust Units.  No conversion,retraction, redemption or pre-emptive rights attach to the Trust Units.

 

**Special Voting Unit**

** **

The TrustIndenture also provides for the issuance of special voting units which are tobe issued to a trustee and which are entitled to such number of votes atmeetings of Unitholders equal to the number of Trust Units reserved forissuance that such special voting units represent, such number of votes and anyother rights or limitations prescribed by the Board of Directors of ARCResources when the Board authorizes issuing such special voting units.

 

A SpecialVoting Unit has been designated by the Board of Directors of ARC Resources asthe Special Voting Unit, Exchangeable Shares (“Special Voting Unit”).  The Special Voting Unit possesses a number ofvotes for the election of directors of ARC Resources and on all other matterssubmitted to a vote of Unitholders equal to the number of outstanding ExchangeableShares from time to time not owned by Trust or ARC Subco.  The holders of Trust Units and the holder ofthe Special Voting Unit vote together as a single class on all matters.

 

In the eventof any liquidation, dissolution or winding-up of Trust, the holder of theSpecial Voting Unit will not be entitled to receive any of our assets availablefor distribution to Unitholders.  Theholder of the Special Voting Unit will not be entitled to receive dividends.  The Special Voting Unit has been issued toComputershare Trust Company of Canada, as trustee.  At such time as the Special Voting Unit hasno votes attached to it because there are no Exchangeable Share outstandingthat are not owned by Trust or ARC Subco, the Special Voting Unit will becancelled.

 

**The Trust Indenture**

** **

The TrustIndenture, among other things, provides for the calling of meetings ofUnitholders, the conduct of business thereof, notice provisions, theappointment and removal of the Trustee and the form of Trust Unit certificates. The Trust Indenture may be amended fromtime to time. Substantive amendments to the Trust Indenture, including earlytermination of the Trust and the sale or transfer of the property of the Trustas an entirety or substantially as an entirety requires approval by SpecialResolution of Unitholders.  Any approvalor consent of Unitholders in relation to any matter required by any regulatorybody will require a majority of, or such other level of approval of Unitholdersas may be stipulated by such regulatory authority, including as to theexclusion of interested or other Unitholders in the calculation of such levelof approval.  See “Meetings and Voting”.

 

The followingis a summary of certain provisions of the Trust Indenture.  For a complete description of such indenture,reference should be made to the Trust Indenture, a copy of which has been filedon SEDAR at www.sedar.com, or may be obtained from the Trustee.

 

**Trustee**

** **

ComputershareTrust Company of Canada is the trustee of the Trust and also acts as thetransfer agent for the Trust Units.  TheTrustee is responsible for, among other things: (a) acceptingsubscriptions for Trust Units and issuing Trust Units pursuant thereto; (b) maintainingbooks and records of the Trust and providing timely reports to holders of TrustUnits; and (c) paying distributions to Unitholders.  The Trust Indenture provides that the Trusteeshall exercise its powers and carry out its functions thereunder as Trusteehonestly, in good faith and in the best interests of the Trust and Unitholdersand, in connection therewith, shall exercise that degree of care, diligence andskill that a reasonably prudent trustee would exercise in comparablecircumstances.

 

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The term of the Trustee’s appointment isuntil the next annual meeting of Unitholders. At each annual meeting the Trustee may be reappointed or changed asdetermined by a majority of the votes cast at such meeting of Unitholders.  The Trustee may resign upon 60 days’notice to the Trust.  The Trustee mayalso be removed by a Special Resolution of the Unitholders.  Such resignation or removal becomes effectiveupon the acceptance or appointment of a successor trustee.

 

ARC Resources presently administers the Truston behalf of the Trustee.  ARC Resources,on behalf of the Trustee, keeps such books and records as are necessary for theproper recording of the business transactions of the Trust.

 

The Trust Indenture provides that the Trusteeshall be under no liability for any action or failure to act unless suchliabilities arise out of the Trustee’s gross negligence, wilful default orfraud.  The Trustee, where it has met itsstandard of care, shall be indemnified out of the assets of the Trust for anytaxes or other government charges imposed upon the Trustee in consequence ofits performance of its duties but shall have no additional recourse againstUnitholders.  In addition, the TrustIndenture contains other customary provisions limiting the liability of theTrustee.

 

**FutureOfferings**

 

Under the Trust Indenture, the Trust mayoffer additional Trust Units or rights to acquire additional Trust Units atsuch times and on such terms as the Board of Directors of ARC Resources maydetermine.  At the option of the Trust,the net proceeds from any offerings may be used to finance the acquisition ofadditional properties, make additional capital expenditures or to repayindebtedness incurred in connection with such acquisitions.

 

**Meetings andVoting**

 

There will be at least one meeting ofUnitholders held annually.  Specialmeetings of Unitholders may be called at any time by the Trustee and shall becalled by the Trustee upon the written request of Unitholders holding in aggregatenot less than 20 per cent of the Trust Units. Notice of all meetings of Unitholders shall be given to Unitholders atleast 21 days prior to the meeting.

 

Unitholders will be entitled at each annualmeeting to appoint the Trustee, to appoint the auditors of the Trust and toelect all the members of the Board of Directors of ARC Resources.

 

**Our Management**

 

The Trust Indenture provides for delegationto ARC Resources by the Trustee of broad discretion to administer and manageour day to day operations, which includes responsibility and authority to makeexecutive decisions on behalf of all of our direct or indirect subsidiaries andto exercise the powers of the Trustee. Without limitation of the foregoing, ARC Resources has been specificallydelegated to provide certain administrative and support services to us,including those necessary: (i) to ensure compliance with continuousdisclosure obligations under applicable securities legislation; (ii) toprovide investor relations services; (iii) to provide or cause to beprovided to Unitholders all information to which Unitholders are entitled underthe Trust Indenture; (iv) to call, hold and distribute materials includingnotices of meetings and information circulars in respect of all necessarymeetings of Unitholders; (v) to determine the amounts payable from time totime to Unitholders and to arrange for distributions to Unitholders ofdistributable income; and (vi) to determine the timing and terms of futureofferings of Trust Units, if any.

 

ARC Resources has accepted all suchdelegation and has agreed that, in respect of such matters, it shall carry outits functions honestly, in good faith and in our best interests and the bestinterests of Unitholders and, in connection therewith, shall exercise thatdegree of care, diligence and skill that a reasonably prudent person wouldexercise in comparable circumstances.

 

**Limitation onNon-Resident Ownership**

 

The Trust intends to comply with therequirements under the Tax Act for “unit trusts” and “mutual fund trusts” atall relevant times such that we maintain our status of a unit trust and amutual fund trust for purposes of the Tax Act. In this regard, we may, from time to time, among other things, take allnecessary steps to monitor the activities of the

 

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Trust and ownership of the Trust Units.  If at any time we become aware that theactivities of the Trust and ownership of the Trust Units by non-residents(non-residents of Canada and partnerships) may threaten the status of the Trustunder the Tax Act as a “unit trust” or “mutual fund trust”, we are authorizedto take such action as may be necessary in the opinion of ARC Resources tomaintain the status of the Trust as a unit trust and a mutual fund trust,including the imposition of restrictions on the issuance by the Trust, or thetransfer by any Unitholder, of Trust Units to a non resident. See “Risk Factors– Change of Legislation”, “Risk Factors – Non-Resident Ownership of Trust Units”and “Risk Factors – Additional Risk Factors Applicable to Residents of theUnited States and Other Non-Residents of Canada”.

 

**Right ofRedemption**

 

Trust Units will be redeemable at any time ondemand by the holders thereof upon delivery to us of the certificate orcertificates representing such Trust Units, accompanied by a duly completed andproperly executed notice requesting redemption. Upon receipt of the redemption request, all rights to and under theTrust Units tendered for redemption shall be surrendered and the holder thereofshall be entitled to receive a price per Unit (“Market Redemption Price”) equalto the lesser of: (i) 90 per cent of the market price, being the weightedaverage trading price of the Trust Units on the principal market on which theTrust Units are quoted for trading during the 10 trading day period commencingimmediately after the date on which the Trust Units are surrendered forredemption; and (ii) the closing market price on the principal market onwhich the Trust Units are quoted for trading on the date that the Trust Unitsare surrendered for redemption.

 

The aggregate cash Market Redemption Pricepayable by us in respect of any Trust Units surrendered for redemption duringany calendar month shall be satisfied by way of a cash payment on the last dayof the following month; provided that the entitlement of Unitholders to receivecash upon the redemption of their Trust Units is subject to a number ofconditions, including the condition that the total amount payable by us inrespect of such Trust Units and all other Trust Units tendered for retractionin the same calendar month must not exceed $100,000 provided that we may waivesuch condition in respect of any calendar month.

 

If a Unitholder is not entitled to receivecash upon the redemption of Trust Units then we shall, at the discretion of theBoard of Directors of ARC Resources, pay the Market Redemption Price bydistributing either: (i) unsecured subordinated promissory notes bearinginterest at 4.5 per cent with a 20 year term, or (ii) distributing aportion of some or all of the assets of ARC having in the opinion of the Boardof Directors of ARC Resources a fair market value equal to the MarketRedemption Price.  Alternatively, theBoard of Directors of ARC Resources may decide to distribute a pro rata shareof the assets of the Trust, net of any liabilities of the Trust.

 

It is anticipated that the foregoingretraction right will not be the primary mechanism for holders of Trust Unitsto dispose of their Trust Units.  ARCResources Notes which may be distributed *inspecie* to Unitholders in connection with a redemption will not belisted on any stock exchange and no market is expected to develop in the ARCResources Notes.  ARC Resources Notes maybe subject to resale restrictions under applicable securities laws.  ARC Resources Notes so distributed may bequalified investments for trusts governed by registered retirement savingsplans, registered retirement income trusts and deferred profit sharing plans.

 

**Termination ofthe Trust**

 

Unitholders may vote to terminate the Trust atany meeting of Unitholders, subject to the following: (a) a vote may onlybe held if requested in writing by the holders of not less than 20 per cent ofthe Trust Units; (b) a quorum of 50 per cent of the issued and outstandingTrust Units is present in person or by proxy; and (c) the termination mustbe approved by Special Resolution of Unitholders.

 

Unless the Trust is terminated or extended byvote of Unitholders earlier, the Trustee shall commence to wind-up the affairsof the Trust on December 31, 2095. In the event that the Trust iswound-up, the Trustee will liquidate all the assets of the Trust, pay, retire,discharge or make provision for some or all obligations of the Trust and thendistribute the remaining proceeds of sale to Unitholders.

 

**Reporting toUnitholders**

** **

Our financial statements will be auditedannually by an independent recognized firm of chartered accountants.  Our audited financial statements, togetherwith the report of such chartered accountants, will be mailed to Unitholders

 

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and the unaudited interim financialstatements of the Trust will be mailed to Unitholders as prescribed bysecurities legislation.  Our year end is December 31.  We are subject to the continuous disclosure obligationsunder all applicable securities legislation.

 

Unitholders are entitled to inspect, duringnormal business hours, at the offices of the Trustee, and, upon payment ofreasonable reproduction costs, to receive photocopies of certain materialcontracts, the Trust Indenture and a listing of the registered holders ofTrust Units.

 

**DistributionReinvestment and Optional Trust Unit Purchase Plan**

** **

A plan has been established to provideUnitholders who are residents of Canada (within the meaning of the Tax Act)with a method to reinvest distributions by purchasing additional Trust Units.

 

**CORPORATE GOVERNANCE**

** **

**General**

** **

In general, ARC Resources has been delegatedsubstantially all of our management decisions. Unitholders are entitled to elect all of the Board of Directors of ARCResources pursuant to the terms of the Trust Indenture.  The Articles of ARC Resources were amended onMarch 20, 2008 to provide that the Board of Directors of ARC Resourcesshall consist of a minimum of three and a maximum of 12 directors.

 

**TrustIndenture**

** **

Pursuant to the Trust Indenture, Unitholdersare entitled to direct the manner in which we will vote our shares in ARCResources at all meetings in respect of matters, relating to the election ofthe directors of ARC Resources, approving its financial statements andappointing auditors of ARC Resources who shall be the same as ourauditors.  Prior to exercising our votingrights in ARC Resources, each Unitholder is entitled to vote on the basis ofone vote per Trust Unit held, and we are required to vote our shares in ARCResources in accordance with the result of the vote of Unitholders.

 

**DecisionMaking**

** **

The Board of Directors of ARC Resources has amandate to supervise the management of our business and affairs and to act witha view to our best interests.  The Boardof Directors of ARC Resources supervises the management of the business andaffairs of our subsidiaries.  The Boardof Directors’ mandate includes: (a) the responsibility for managing ouraffairs; (b) monitoring our management and our activities; (c) reviewingstrategic operating, capital and financial plans; and (d) compliancereporting and corporate communications. In particular, significant operational decisions and all decisionsrelating to: (i) the acquisition and disposition of properties for apurchase price or proceeds in excess of an amount prescribed from time to timeby the Board of Directors; (ii) the approval of capital expenditurebudgets; and (iii) establishment of credit facilities are made by the Boardof Directors of ARC Resources.  Inaddition, the Trustee has delegated broad discretion in relation to our day today operations to the Board of Directors of ARC Resources including alldecisions relating to:  (i) mattersrelating to any offers for Trust Units; (ii) issuances of additional TrustUnits; and (iii) the determination of the amount of distributableincome.  Any amendment to the royaltyagreements requires the approval of the Board of Directors of ARC Resources onour behalf.  The Board of Directors ofARC Resources holds regularly scheduled meetings at least quarterly to reviewthe business and affairs of our subsidiaries and make any necessary decisionsrelating thereto.

 

The Trust Indenture gives to the Board ofDirectors of ARC Resources the authority to exercise the rights, powers andprivileges for all matters relating to the maximization of Unitholder value inthe context of an offer including any Unitholder rights protection plan, anydefensive action to an offer, any directors circular in response to an offer,any regulatory or court proceeding relating to an offer and any related orancillary matter.

 

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**Board ofDirectors of ARC Resources**

** **

ARC Resources has a Board of Directorsconsisting of nine individuals, eight of whom have been elected by Unitholders,including by the holders of the Exchangeable Shares through the Special VotingUnit and one of whom, James C. Houck, was appointed as an addition to the Boardof Directors on February 14, 2008.

 

The name, municipality of residence, positionheld and principal occupation of each director and officer of ARC Resources areset out below:

 
| **Name and  Municipality of Residence**              | ** ** | **Offices Held  and Time as Director**              | ** ** | **Principal Occupation**                                                  |
|---------------------------------------------------------------------|------------|-------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------|
|                                                                |       |                                                                    |       |                                                                           |
| Mac H.  Van Wielingen(1)(3)(4)  Calgary, Alberta, Canada       |       | Chairman of the Board and  Director since May 3, 1996              |       | Co-Chairman of ARC  Financial Corporation (an investment management company)   |
|                                                                |       |                                                                    |       |                                                                           |
| Walter DeBoni(1) (4) (5)  Calgary, Alberta, Canada        |       | Vice Chairman and Director since June 26,  1996                    |       | Independent Businessman                                                        |
|                                                                |       |                                                                    |       |                                                                           |
| John P. Dielwart  Calgary, Alberta, Canada                          |       | President, Chief Executive  Officer and Director since May 3, 1996 |       | President and Chief  Executive Officer of ARC Resources                        |
|                                                                |       |                                                                    |       |                                                                           |
| Frederic C. Coles(2)(3) (5)  Calgary, Alberta, Canada          |       | Director since May 3,  1996                                        |       | Independent Businessman                                                        |
|                                                                |       |                                                                    |       |                                                                           |
| Fred J. Dyment(1)(2)  Calgary, Alberta, Canada                      |       | Director since  April 17, 2003                                     |       | Independent Businessman                                                        |
|                                                                |       |                                                                    |       |                                                                           |
| James C. Houck  Calgary, Alberta, Canada                            |       | Director since February 14,  2008                                  |       | Independent Businessman                                                        |
|                                                                |       |                                                                    |       |                                                                           |
| Michael M. Kanovsky(1)(2)  Victoria, B.C., Canada                   |       | Director since May 3,  1996                                        |       | Independent Businessman                                                        |
|                                                                |       |                                                                    |       |                                                                           |
| Herbert C.  Pinder, Jr.(3)(4)  Saskatoon, Saskatchewan, Canada |       | Director since  January 1, 2006                                    |       | Independent Businessman                                                        |
|                                                                |       |                                                                    |       |                                                                           |
| John M. Stewart(3)(4)(5)  Scottsdale, Arizona, U.S.A.               |       | Director since  February 11, 1998                                  |       | Vice Chairman of ARC  Financial Corporation (an investment management company) |
|                                                                |       |                                                                    |       |                                                                           |
| Doug J. Bonner  Calgary, Alberta, Canada                            |       | Senior Vice-President,  Corporate Development                           |       | Senior Vice-President,  Corporate Development of ARC Resources                 |
|                                                                |       |                                                                    |       |                                                                           |
| David P. Carey  Calgary, Alberta, Canada                            |       | Senior Vice-President,  Capital Markets                                 |       | Senior Vice-President,  Capital Markets of ARC Resources                       |
|                                                                |       |                                                                    |       |                                                                           |
| Terry Gill  Calgary, Alberta, Canada                                |       | Senior Vice-President,  Corporate Services                              |       | Senior Vice-President,  Corporate Services of ARC Resources                    |
|                                                                |       |                                                                    |       |                                                                           |
| Steven W. Sinclair  Calgary, Alberta, Canada                        |       | Senior Vice-President,  Finance and Chief Financial Officer             |       | Senior Vice-President,  Finance and Chief Financial Officer of ARC Resources   |
|                                                                |       |                                                                    |       |                                                                           |
| Myron M. Stadnyk  Calgary, Alberta, Canada                          |       | Senior Vice-President and  Chief Operating Officer                      |       | Senior Vice-President and  Chief Operating Officer of ARC Resources            |
|                                                                |       |                                                                    |       |                                                                           |
| Terry M. Anderson  Calgary, Alberta, Canada                         |       | Vice-President, Operations                                              |       | Vice-President, Operations  of ARC Resources                                   |
|                                                                |       |                                                                    |       |                                                                           |
| Yvan Chrétien  Calgary, Alberta, Canada                        |       | Vice-President, Land                                                    |       | Vice-President, Land of  ARC Resources                                         |

 

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| **Name and  Municipality of Residence** | ** ** | **Offices Held  and Time as Director** | ** ** | **Principal Occupation**                                                      |
|--------------------------------------------------------|------------|------------------------------------------------------------|------------|------------------------------------------------------------------------------------|
| ** **                                             | ** ** | ** **                                                 | ** ** | ** **                                                                         |
| Ingram B. Gillmore  Calgary, Alberta, Canada           |       | Vice-President,  Engineering                               |       | Vice-President,  Engineering of ARC Resources                                      |
|                                                   |       |                                                       |       |                                                                               |
| P. Van R. Dafoe  Calgary, Alberta, Canada              |       | Vice-President and  Treasurer                              |       | Vice-President and  Treasurer of ARC Resources                                     |
|                                                   |       |                                                       |       |                                                                               |
| Allan R. Twa  Calgary, Alberta, Canada                 |       | Secretary                                                  |       | Partner, Burnet, Duckworth & Palmer LLP (barristers and  solicitors) |

 

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Notes:

(1)                                  Member of Audit Committee in 2007.

(2)                                  Member of Reserves Committeein 2007.

(3)                                  Member of Human Resources andCompensation Committee in 2007.

(4)                                  Member of Policy and BoardGovernance Committee in 2007.

(5)                                  Member of Health, Safety andEnvironment Committee in 2007.

 

With the appointment of Mr. Houck to theBoard of Directors on February 14, 2008, the membership of the committeesof the Board of Directors were changed and a new committee formed, the RiskCommittee, as follows:

 
| **Name of  Director**  | ** ** | **Audit  Committee** | ** ** | **Reserves  Committee** | ** ** | **Risk  Committee** | ** ** | **Human  Resources &  Compensation  Committee** | ** ** | **Policy and  Board  Governance  Committee** | ** ** | **Health, Safety & Environment  Committee** |
|-----------------------------|------------|----------------------|------------|-------------------------|------------|---------------------|------------|----------------------------------------------------------|------------|---------------------------------------------------|------------|------------------------------------------------------|
| Mac Van Wielingen           |       |                 |       |                    |       | ü              |       | ü                                                   |       | ü                                            |       |                                                 |
| Walter DeBoni               |       | ü               |       |                    |       | ü              |       |                                                     |       | ü                                            |       |                                                 |
| John P. Dielwart            |       |                 |       |                    |       |                |       |                                                     |       |                                              |       |                                                 |
| Frederic C. Coles           |       |                 |       | ü                  |       |                |       | ü                                                   |       |                                              |       | ü                                               |
| Fred J. Dyment              |       | ü               |       | ü                  |       | ü              |       |                                                     |       |                                              |       |                                                 |
| James C. Houck              |       | ü               |       | ü                  |       |                |       |                                                     |       |                                              |       | ü                                               |
| Michael M. Kanovsky         |       |                 |       | ü                  |       | ü              |       |                                                     |       | ü                                            |       |                                                 |
| Herbert C. Pinder, Jr. |       |                 |       |                    |       |                |       | ü                                                   |       | ü                                            |       | ü                                               |
| John M. Stewart             |       | ü               |       |                    |       |                |       | ü                                                   |       |                                              |       | ü                                               |

 

With the exception of the followingindividuals, the officers and directors have held the position set forth as hisprincipal occupation for the last five years: Prior to 2005, Walter DeBoni, was Vice-President, Canada Frontier &International Business of Husky Energy Inc. (a public oil and gas company);prior to November 2005, Steven W. Sinclair, was Vice-President, Financeand Chief Financial officer, David P. Carey was Vice-President, BusinessDevelopment, Doug Bonner was Vice-President, Engineering, Myron J. Stadnyk, wasVice-President, Operations and Land and prior to September 2004 was VicePresident Operations, of ARC Resources. Prior to March 2005, P. Van R. Dafoe, was Controller of ARCResources and prior to July 2007 was Treasurer of ARC Resources.  Prior to November 2005, Terry M.Anderson, was Manager, Field Operations of ARC Resources, and Yvan Chretien wasLand Manager of ARC Resources.  Prior to January 2007,Ingram Gillmore was Engineering Manager of ARC Resources.  Prior to September 2008, Terry Gill, wasSenior Vice President Human Resources at Superior Propane.  Prior to October 2007, Mr. JamesHouck was President and Chief Executive Officer and a director of Western OilSands Ltd. and prior to April 1, 2005, Mr. Houck held several seniorpositions with Chevron Texaco Inc.

 

The following comprises a brief description ofthe background of the officers of ARC Resources.

 

***John P. Dielwart, B.Sc., P.Eng.***

 

Mr. Dielwart is President and ChiefExecutive Officer of ARC Resources Ltd. and has overall managementresponsibility for the Trust. Prior to joining ARC in 1994, Mr. Dielwartspent 12 years with a major Calgary based oil and natural gas engineeringconsulting firm, as senior vice-president and a director, where he gainedextensive

 

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technical knowledge of oil and natural gasproperties in western Canada. He began his career working for five years with amajor oil and natural gas company in Calgary. Mr. Dielwart is aPast-Chairman of the board of governors for the Canadian Association ofPetroleum Producers (CAPP). He holds a Bachelor of Science with Distinction(Civil Engineering) degree, University of Calgary. He has also been a directorof ARC since 1996.

 

***Steven W. Sinclair, B. Comm., CA***

*** ***

Mr. Sinclair is Senior Vice-PresidentFinance and Chief Financial Officer of ARC Resources Ltd. and oversees all ofthe financial and accounting affairs of ARC Energy Trust. Mr. Sinclair hasa Bachelor of Commerce from the University of Calgary, and a CharteredAccountant’s designation which he received in 1981. He has over 25 years experiencewithin the finance, accounting and taxation areas of the oil and gas industryand has been with the Trust since 1996. Mr. Sinclair is also a member ofthe Alberta and Canadian Institutes of Chartered Accountants.

 

***Myron M. Stadnyk, P.Eng.***

*** ***

Mr. Stadnyk is Senior Vice-President andChief Operating Officer of ARC Resources Ltd. and is responsible for allaspects of ARC’s ongoing operational and production management and strategies.He has over 25 years experience in the oil and gas business. Prior to joiningARC Resources Ltd. in 1997, Mr. Stadnyk worked with a major oil and gascompany in both domestic and international operations. He has a B.Sc. inMechanical Engineering from the University of Saskatchewan and is a member ofthe Association of Professional Engineers.

 

***Doug J. Bonner, P.Eng.***

*** ***

Mr. Bonner is Senior Vice-President,Corporate Development of ARC Resources Ltd. and is responsible for thestrategic development of ARC’s enhanced oil recovery assets. He holds a B.Sc.in Geological Engineering from the University of Manitoba. Mr. Bonner’smajor area of expertise is reservoir engineering and he has extensive technicalknowledge of oil and natural gas fields throughout western Canada, the eastcoast and northern Canada. Prior to joining ARC in 1996, Mr. Bonner spent18 years with various major oil and natural gas companies in positions ofincreasing responsibility.

 

***David P. Carey, P.Eng., MBA***

*** ***

Mr. Carey is Senior Vice-President,Capital Markets of ARC Resources Ltd. and is responsible for all facets ofinvestor relations and corporate governance. He holds both a B.Sc. inGeological Engineering and a MBA from Queen’s University. Mr. Carey bringsover 25 years of diverse experience in the Canadian and International energyindustries covering exploration, production and project evaluations in westernCanada, oilsands, the Canadian frontiers and internationally. Prior to joiningARC Resources in 2001, Mr. Carey held senior positions with Athabasca OilSands Trust and a major Canadian oil and gas company.

 

***Terry Gill, B.PE.***

*** ***

Mr. Gill is Senior Vice-President,Corporate Services of ARC Resources Ltd. and oversees all human resources,information technology and office services related activities. Prior to joiningARC in September 2007, Mr. Gill spent eight years with a majornational distribution company as a senior executive. He also spent 10 years inthe oil and gas industry and has broad experience in all areas of talentmanagement. Mr. Gill has coached high performance athletes at an elitelevel and holds a B.PE. in coaching leadership from the University of Alberta.

 

***Terry M. Anderson, P.Eng.***

*** ***

Mr. Anderson is Vice-President,Operations of ARC Resources Ltd. and is responsible for all of ARC’soperational activities. He has a B.Sc. in Petroleum Engineering and is a memberof the Association of Professional Engineers in Alberta, Saskatchewan andBritish Columbia. Mr. Anderson has over 10 years of experience indrilling, completion, pipeline, facility and production operations.  Prior to joining ARC in 2000, he worked at amajor oil and gas company.

 

35

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***Yvan Chretien, B.Comm.***

*** ***

Mr. Chretien is Vice-President, Land ofARC Resources Ltd. and is responsible for all of ARC’s land related activities.He has over 15 years of related experience in the oil and gas business.  Prior to joining ARC in 2001, Mr Chretienworked for both senior and intermediate oil and gas companies.

 

***Ingram B. Gillmore, P.Eng.***

*** ***

Mr. Gillmore is Vice-President,Engineering of ARC Resources Ltd. and is responsible for all of ARC’sengineering, geophysical, geological and joint venture related activities. Heholds a B.Sc. in Chemical engineering from the University of Waterloo (1991)and a Bachelor of Fine Arts. Mr. Gillmore has been at ARC since 2002.Prior to joining ARC, Mr. Gillmore held positions with several major oiland gas companies.

 

***P. Van R. Dafoe, B. Comm., CMA***

*** ***

Mr. Dafoe is Vice-President andTreasurer of ARC Resources Ltd. and is responsible for all of ARC’s Hedging andTreasury related activities. He has a Bachelor of Commerce – Honours from theUniversity of Manitoba and obtained his Certified Management Accountant’sdesignation in 1995. Mr. Dafoe joined ARC in 1999 after 13 years withvarious companies in the finance and accounting area of the oil and gasindustry.

 

***Allan R. Twa, Q.C.***

*** ***

Mr. Twa acts is Corporate Secretary ofARC Resources Ltd. A member of the Alberta Bar since 1971, Mr. Twa is apartner in the law firm Burnet, Duckworth & Palmer LLP. Mr. Twaholds a B.A. (Political Science) from the University of Calgary, a LL.B. fromthe University of Alberta and a LL.M. from the University of London, England.Over the last 30 years, Mr. Twa has been engaged in a legal practiceinvolving legal administration of public companies and trusts, corporatefinance, and mergers and acquisitions.

 

Mac Van Wielingen is the Chairman and aDirector of ARC Resources and was a director of Gauntlet Energy Corporationwhich secured creditor protection pursuant to the *Companies’ Creditors Arrangement Act* on June 17, 2003and was subsequently acquired by Ketch Resources Ltd. in December, 2003.

 

All of the directors of ARC Resources wereelected on May 23, 2007 to hold office until the next annual generalmeeting of ARC Resources, which is scheduled for May 12, 2008, except forJames C. Houck who was appointed as an addition to the Board of Directors on February 14,2008.  As at December 31, 2007, thedirectors and officers of ARC Resources, as a group, beneficially owned, orcontrolled or directed, directly or indirectly, 754,945 Trust Units orapproximately 0.36 per cent ofthe outstanding Trust Units, and 786,737 Exchangeable Shares or approximately60 per cent of the outstanding Exchangeable Shares.  If all of the Exchangeable Shares had beenexchanged for Trust Units at the Exchange Ratio in effect on December 31,2007, the directors and officers of ARC Resources as a group would hold2,524,914 Trust Units or approximately 1.18 per cent of the outstanding TrustUnits as at December 31, 2007.

 

See “Risk Factors – Reliance on Key Membersof Management”.

 

**AUDIT COMMITTEEDISCLOSURES**

** **

Multilateral Instrument 52-110 (“MI 52-110”)relating to audit committees has mandated certain disclosures for inclusion inthis Annual Information Form.  The textof the Audit Committee’s mandate is attached as Appendix C to this AnnualInformation Form.

 

**Members of theAudit Committee**

** **

As of December 31, 2007, the members ofthe Audit Committee were Fred J. Dyment, chairman, and Walt DeBoni, MichaelKanovsky and Mac Van Wielingen, each of whom is independent and financiallyliterate within the meaning of MI 52-110. As of February 14, 2008, Mac Van Wielingen and Michael Kanovskywere replaced by James C. Houck and John M. Stewart, each of whom isindependent and financially literate within the meaning of MI 52-110.  The following comprises a brief summary ofeach such past member’s and member’s education and experience:

 

36

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***Fred J. Dyment***

*** ***

Mr. Dyment has 30 years experience in the oil and gas business andis currently an independent businessman. His past business career includedpositions as President and CEO for Maxx Petroleum and President and CEO ofRanger Oil Limited. Mr. Dyment received a Chartered Accountant designationfrom the province of Ontario in 1972. Mr. Dyment currently sits as aDirector on the Boards of Tesco Corporation, Western Oil Sands, ZCL CompositesInc. and Transglobe Energy Corporation. He has been a Director of ARC since 2003.

 

***Walt DeBoni***

*** ***

Mr. DeBoni retired from Husky Energy Inc. where he held theposition of VP, Canada Frontier & International Business. Prior tothis Mr. DeBoni was CEO of Bow Valley Energy for a number of years. Inaddition to his time at Husky and Bow Valley he has also held numerous top executiveposts in the oil and gas industry with major corporations. Mr. DeBoniholds a B.A.Sc. Chem. Eng. from the University of British Columbia, a MBAdegree with a major in Finance from the University of Calgary and is a memberof the association of Professional Engineers, Geologists and Geophysicists ofAlberta and the Society of Petroleum Engineers. He is a past Chairman of thePetroleum Society of CIM, a past Director of the Society of Petroleum Engineersand has been a Director of ARC Resources since 1996.

 

***Michael Kanovsky***

*** ***

Mr. Kanovsky graduated from Queen’s University with a B.Sc.,P.Eng. and the Ivey School of Business. Mr. Kanovsky’s business careerincluded the position of VP of Corporate Finance with a major Canadianinvestment dealer followed by co-founding Northstar Energy Corporation andPowerLink Corporation (electrical cogeneration) where he served as ExecutiveBoard Chairman and Director. Mr. Kanovsky is, amongst others, a Directorof Bonavista Petroleum Inc. and Devon Energy Corporation. He has been aDirector of ARC since 1996.

 

***Mac Van Wielingen***

*** ***

Mr. Van Wielingen has served as a Director of ARC Resources Ltd.since its formation in 1996. He is Co-Chairman and a founder of ARC FinancialCorporation. Previously Mr. Van Wielingen was a Senior Vice-President andDirector of a major national investment dealer responsible for all corporatefinance activities in Alberta. He has managed numerous significant corporatemerger and acquisition transactions, capital raising projects and equity investmentsrelating to the energy sector. Mr. Van Wielingen holds an Honours BusinessDegree from the University of Western Ontario Business School and has studiedpost-graduate Economics at Harvard University.

 

***James C. Houck***

*** ***

Mr. JamesC. Houck was the President and Chief Executive Officer and a director ofWestern Oils Sands Ltd. until October 18, 2007.  Mr. Houck has a B.Sc. from TrinityUniversity and an MBA from the University of Houston.  Mr. Houck has over 35 years of industryexperience, primarily with Chevron Texaco Inc. where he held a number of seniormanagement positions.

 

***John M. Stewart***

*** ***

Mr. Stewartis Vice-Chairman and a founder of ARC Financial Corporation.  Mr. Stewart has a B.Sc. in Engineeringfrom the University of Calgary and an MBA from the University of BritishColumbia.  Prior to ARC Financial he wasa director and Vice-President of a major investment dealer.

 

**PrincipalAccountant Fees and Services**

** **

The Audit Committee has not adopted specificpolicies and procedures for the engagement of non-audit services andpre-approves each such engagement or type of engagement for every fiscal year.

 

Our external auditor is Deloitte &Touche LLP.  The following is a summaryof the external audit services fees by category.

 

37

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***Audit Fees***

 

The aggregatefees billed by our external auditor for audit services are:

 
| 2007 |   | $ | 768,375 |   |
|------|--------|---|---------|--------|
| 2006 |   | $ | 293,426 |   |

 

***Audit Related Fees***

 

The aggregatefees billed by our external auditor for assurance and related services that arereasonably related to the performance of the audit or review of the financialstatements (not included in audit services fees) are:

 
| 2007 |   | $ | 71,724  |   |
|------|--------|---|---------|--------|
| 2006 |   | $ | 444,200 |   |

 

***Tax Fees***

*** ***

The aggregatefees billed by our external auditor for professional services for municipal propertytax compliance, tax advice and tax planning are:

 
| 2007 |   | $ | 139,780 |   |
|------|--------|---|---------|--------|
| 2006 |   | $ | 158,195 |   |

 

***All Other Fees***

 

The aggregatefees billed by our external auditor for products and services not includedunder the headings:  Audit Fees, AuditRelated Fees, Tax Fees and All Other Fees.

 
| 2007 |   | $ | Nil |   |
|------|--------|---|-----|--------|
| 2006 |   | $ | Nil |   |

 

**CONFLICTS OF INTEREST**

** **

The Board of Directors has adopted a Code ofBusiness Conduct and Ethics and a Code of Ethics for Senior Financial Officers(the “Codes”).  In general, the privateinvestment activities of employees, directors and officers are not prohibited,however, should an existing investment pose a potential conflict of interestthe potential conflict is required by the Codes to be disclosed to thePresident or the Board of Directors.  Anyother activities of employees which pose a potential conflict of interest arealso required by the Codes to be disclosed to the President or the Board ofDirectors.  Any such potential conflictsof interests will be dealt with openly with full disclosure of the nature andextent of the potential conflicts of interests with the Trust.

 

It is acknowledged in the Codes that employees,officers and directors may be directors or officers of other entities engagedin the oil and gas business, and that such entities may compete directly orindirectly with the Trust.  No assurancecan be given that opportunities identified by directors of ARC Resources willbe provided to us.  Passive investmentsin public or private entities of less than one per cent of the outstandingshares will not be viewed as “competing” with the Trust.  Any director, officer or employee of ARCResources which is a director or officer of any entity engaged in the oil andgas business shall disclose such occurrence to the Board of Directors.  Any director, officer or employee of ARCResources who is actively engaged in the management of, or who owns aninvestment of one per cent or more of the outstanding shares, in public orprivate entities shall disclose such holding to the Board of Directors.  In the event that any circumstance shouldarise as a result of such positions or investments being held or otherwisewhich in the opinion of the Board of Directors constitutes a conflict ofinterest which reasonably affects such person’s ability to act with a view tothe best interests of the Trust, the Board of Directors will take such actionsas are reasonably required to resolve such matters with a view to the bestinterests of the Trust.  Such actions,without limitation, may include excluding such directors, officers or employeesfrom certain information or activities of the Trust.

 

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The *BusinessCorporations Act* (Alberta) provides that in the event that anofficer or director is a party to, or is a director or an officer of or has amaterial interest in any person who is a party to, a material contract ormaterial transaction or proposed material contract or proposed materialtransaction, such officer or director shall disclose the nature and extent ofhis or her interest and shall refrain from voting to approve such contract ortransaction.

 

**INTEREST OF MANAGEMENTAND OTHERS IN MATERIAL TRANSACTIONS**

** **

There is no material interest, direct orindirect, of any director or senior officer, or to our knowledge any person orcompany that is the direct or beneficial owner, or who exercises control ordirection over more than 10 per cent of outstanding Trust Units, or anyassociate or affiliate of any of the foregoing, in any transaction within the threemost recently completed financial years.

 

**DISTRIBUTIONS TOUNITHOLDERS**

** **

Thefollowing per Trust Unit distributions have been made in the last threecompleted financial years:

 

| **2005**        | ** ** | **Distribution Per Trust Unit** | ** ** |
|-----------------|------------|------------------------------------------------|------------|
| First  Quarter  |       | $                                              | 0.45       |   |
| Second  Quarter |       | $                                              | 0.45       |   |
| Third  Quarter  |       | $                                              | 0.49       |   |
| Fourth  Quarter |       | $                                              | 0.60       |   |
|            |       |                                           |       |
| **2006**        |       |                                           |       |
| First  Quarter  |       | $                                              | 0.60       |   |
| Second  Quarter |       | $                                              | 0.60       |   |
| Third  Quarter  |       | $                                              | 0.60       |   |
| Fourth  Quarter |       | $                                              | 0.60       |   |
|            |       |                                           |       |
| **2007**        |       |                                           |       |
| First  Quarter  |       | $                                              | 0.60       |   |
| Second  Quarter |       | $                                              | 0.60       |   |
| Third Quarter   |       | $                                              | 0.60       |   |
| Fourth  Quarter |       | $                                              | 0.60       |   |

 

In certain circumstances, distributions maybe restricted by our borrowing agreements. For more information see “OtherInformation Relating to Our Business – Borrowing”.  Distributions paid to Unitholders in 2005 were2 per cent tax deferred, 2006 distributions were 2 per cent tax deferred and2007 distributions were 3 per cent tax deferred.  For more information, see “Our Business –Distributionsand Distribution Policy”.

 

**PRICE RANGE AND TRADINGVOLUME OF TRUST UNITSAND EXCHANGEABLE SHARES**

** **

The TrustUnits are listed and posted for trading on the TSX.  The trading symbol for the Trust Units isAET.UN.  The following table sets forththe high and low closing prices and the aggregate volume of trading of theTrust Units on the TSX for the periods indicated (as quoted by the TSX):

 
| ** **           | ** ** | **Toronto Stock Exchange** | ** ** |
|----------------------|------------|--------------------------------------|------------|
| **2007 Period** | ** ** | **High**                             | ** ** | **Low** | ** ** | ** Volume** | ** ** |
| ** **           | ** ** | **$**                                | ** ** | **$** | ** ** | ** ** | ** ** |
| January              |       | 23.28                                |       | 19.98 |   | 18,565,277 |   |
| February             |       | 23.44                                |       | 21.34 |   | 10,157,408 |   |
| March                |       | 22.40                                |       | 19.81 |   | 13,361,142 |   |
| April                |       | 22.63                                |       | 20.58 |   | 12,225,891 |   |
| May                  |       | 24.00                                |       | 21.75 |   | 14,048,618 |   |
| June                 |       | 23.22                                |       | 21.65 |   | 11,520,408 |   |
| July                 |       | 22.74                                |       | 21.06 |   | 9,472,903 |   |
| August               |       | 21.25                                |       | 18.90 |   | 13,332,903 |   |
| September            |       | 21.40                                |       | 20.13 |   | 8,385,602 |   |

 

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| ** **           | ** ** | **Toronto Stock Exchange** | ** ** |
|----------------------|------------|--------------------------------------|------------|
| **2007 Period** | ** ** | **High**                             | ** ** | **Low** | ** ** | ** Volume** | ** ** |
| ** **           | ** ** | **$**                                | ** ** | **$** | ** ** | ** ** | ** ** |
| October              |       | 21.49                                |       | 20.35 |   | 14,105,891 |   |
| November             |       | 21.55                                |       | 18.90 |   | 13,509,993 |   |
| December             |       | 20.60                                |       | 18.78 |   | 11,711,317 |   |

 

TheExchangeable Shares are listed and posted for trading on the TSX.  The trading symbol for the ExchangeableShares is ARX.  The following table setsforth the high and low closing prices and the aggregate volume of trading ofthe Exchangeable Shares on the TSX for the periods indicated (as quoted by theTSX):

 
| ** **           | ** ** | **Toronto Stock Exchange** | ** ** |
|----------------------|------------|--------------------------------------|------------|
| **2007 Period** | ** ** | **High**                             | ** ** | **Low** | ** ** | ** Volume** | ** ** |
| ** **           | ** ** | **$**                                | ** ** | **$** | ** ** | ** ** | ** ** |
| January              |       | 47.86                                |       | 45.30 |   | 1,200 |   |
| February             |       | 47.27                                |       | 46.56 |   | 1,400 |   |
| March                |       | 46.56                                |       | 45.26 |   | 1,400 |   |
| April                |       | 46.29                                |       | 45.26 |   | 3,164 |   |
| May                  |       | 51.00                                |       | 45.26 |   | 800 |   |
| June                 |       | 50.25                                |       | 48.00 |   | 17,575 |   |
| July                 |       | 48.00                                |       | 46.00 |   | 300 |   |
| August               |       | 46.00                                |       | 42.26 |   | 1,600 |   |
| September            |       | 44.50                                |       | 42.26 |   | 500 |   |
| October              |       | 46.59                                |       | 44.01 |   | 300 |   |
| November             |       | 46.59                                |       | 42.26 |   | 3,800 |   |
| December             |       | 45.00                                |       | 42.26 |   | 3,900 |   |

** **

**INDUSTRY REGULATIONS**

 

The oil and natural gas industry is subjectto extensive controls and regulations governing its operations (including landtenure, exploration, development, production, refining, transportation, andmarketing) imposed by legislation enacted by various levels of government andwith respect to pricing and taxation of oil and natural gas by agreements amongthe governments of Canada, Alberta, British Columbia, and Saskatchewan, all ofwhich should be carefully considered by investors in the oil and gas industry.  It is not expected that any of these controlsor regulations will affect our operations in a manner materially different thanthey would affect other oil and gas companies of similar size.  All current legislation is a matter of publicrecord and we are unable to predict what additional legislation or amendmentsmay be enacted.  Outlined below are someof the principal aspects of legislation, regulations and agreements governingthe oil and gas industry.

 

**Pricing and Marketing - Oil andNatural Gas**

 

Theproducers of oil are entitled to negotiate sales contracts directly with oilpurchasers, with the result that the market determines the price of oil.  Oil prices are primarily based on worldwidesupply and demand.  The specific pricedepends in part on oil quality, prices of competing fuels, distance to themarkets, the value of refined products, the supply/demand balance, and othercontractual terms.  Oil exporters arealso entitled to enter into export contracts with terms not exceeding one yearin the case of light crude oil and two years in the case of heavy crude oil,provided that an order approving such export has been obtained from theNational Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (toa maximum of 25 years) requires an exporter to obtain an export licence fromthe NEB and the issuance of such licence requires the approval of the Governorin Council.

 

The price of natural gas is determined bynegotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB andthe Government of Canada.  Exporters arefree to negotiate prices and other terms with purchasers, provided that theexport contracts must continue to meet certain other criteria prescribed by theNEB and the Government of Canada. Natural gas exports (other than propane, butane and ethane) for a termof less than two years or for a term of two to 20 years (in quantities of notmore than 30,000 m3/day), must be made pursuant to an NEBorder.  Any natural gas export to be madepursuant to a contract of longer duration (to a

 

40

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maximum of 25 years) or a larger quantityrequires an exporter to obtain an export licence from the NEB and the issuanceof such licence requires the approval of the Governor in Council.

 

The governments of Alberta, British Columbia,and Saskatchewan also regulate the volume of natural gas that may be removedfrom those provinces for consumption elsewhere based on such factors as reserveavailability, transportation arrangements, and market considerations.

 

**PipelineCapacity**

 

Althoughpipeline expansions are ongoing, the lack of firm pipeline capacity continuesto affect the oil and natural gas industry and limit the ability to produce andto market natural gas production.  Inaddition, the pro-rationing of capacity on the inter-provincial pipelinesystems also continues to affect the ability to export oil and natural gas.

 

**TheNorth American Free Trade Agreement**

 

The NorthAmerican Free Trade Agreement (“NAFTA”) among the governments of Canada, UnitedStates of America, and Mexico became effective on January 1, 1994.  NAFTA carries forward most of the materialenergy terms that are contained in the Canada United States Free Trade Agreement.  In the context of energy resources, Canadacontinues to remain free to determine whether exports of energy resources tothe United States or Mexico will be allowed, provided that any exportrestrictions do not: (i) reduce the proportion of energy resourcesexported relative to domestic use (based upon the proportion prevailing in themost recent 36 month period); (ii) impose an export price higher than thedomestic price subject to an exception with respect to certain voluntarymeasures which only restrict the volume of exports; and (iii) disruptnormal channels of supply.  All threecountries are prohibited from imposing minimum or maximum export or importprice requirements, provided, in the case of export price requirements,prohibition in any circumstances in which any other form of quantitativerestriction is prohibited, and in the case of import-price requirements, suchrequirements do not apply with respect to enforcement of countervailing andanti-dumping orders and undertakings.

 

NAFTA contemplates the reduction of Mexicanrestrictive trade practices in the energy sector by 2010 and prohibitsdiscriminatory border restrictions and export taxes.  NAFTA also contemplates clearer disciplineson regulators to ensure fair implementation of any regulatory changes and tominimize disruption of contractual arrangements and avoid undue interferencewith pricing, marketing and distribution arrangements, which is important forCanadian natural gas exports.

 

**ProvincialRoyalties and Incentives**

 

***General***

*** ***

In addition tofederal regulation, each province has legislation and regulations which governland tenure, royalties, production rates, environmental protection, and othermatters.  The royalty regime is asignificant factor in the profitability of crude oil, natural gas liquids,sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands aredetermined by negotiations between the mineral owner and the lessee, althoughproduction from such lands is subject to certain provincial taxes androyalties.  Crown royalties aredetermined by governmental regulation and are generally calculated as apercentage of the value of the gross production.  The rate of royalties payable generallydepends in part on prescribed reference prices, well productivity, geographicallocation, field discovery date, method of recovery, and the type or quality ofthe petroleum product produced.  Otherroyalties and royalty-like interests are, from time to time, carved out of theworking interest owner’s interest through non-public transactions.  These are often referred to as overridingroyalties, gross overriding royalties, net profits interests, or net carriedinterests.

 

Occasionally the governments of the westernCanadian provinces create incentive programs for exploration anddevelopment.  Such programs often providefor royalty rate reductions, royalty holidays, and tax credits, and aregenerally introduced when commodity prices are low.  The programs are designed to encourageexploration and development activity by improving earnings and cash flow withinthe industry.  Royalty holidays andreductions would reduce the amount of Crown royalties paid by oil and gasproducers to the provincial governments and would increase the net income andfunds from operations of such producers. However, the trend in recent years has been

 

41

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for provincial governments to eliminate,amend or allow such incentive programs to expire without renewal, and consequentlyfew such incentive programs are currently operative.

 

***Alberta***

*** ***

In Alberta, companies are granted the rightto explore, produce and develop petroleum and natural gas resources in exchangefor royalties, bonus bid payments and rents. Currently, the amount of royalties that are payable is influenced by theoil production, density of the oil, and the vintage of the oil.  Originally, the vintage classified oil in “newoil” and “old oil” depending on when the oil pools were discovered.  If the pool was discovered prior to March 31,1974 is considered “old oil”, if it was discovered after March 31, 1974and before September 1, 1992, is considered “new oil”.  The Alberta government introduced in 1992 aThird Tier Royalty with a base rate of 10 per cent and a rate cap of 25 percent for oil pools discovered after September 1, 1992.  The new oil royalty reserved to the Crown hasa base rate of 10 per cent and a rate cap of 30 per cent.  The old oil royalty reserved to the Crown hasa base rate of 10 per cent and a rate cap of 35 per cent.

 

The royalty reserved to the Crown in respectof natural gas production, subject to various incentives, is between 15 percent and 30 per cent, in the case of new natural gas, and between 15 per centand 35 per cent, in the case of old natural gas, depending upon a prescribed orcorporate average reference price. Natural gas produced from qualifying intervals in eligible gas wellsspudded or deepened to a depth below 2,500 metres is also subject to a royaltyexemption, the amount of which depends on the depth of the well.

 

Oil sands projects are subject to a specificregulation made effective July 1, 1997, and expiring June 30, 2009,which, among other things, determines the Crown’s share of crude and processedoil sands products.

 

Regulations made pursuant to the *Mines and Minerals Act* (Alberta) providedvarious incentives for exploring and developing oil reserves in Alberta.  However, the Alberta Government announced in August of2006 that four royalty programs were to be amended, a new program was to beintroduced and the Alberta Royalty Tax Credit Program (“ARTC”) was to beeliminated, effective January 1, 2007. The programs affected by this announcement are: (i) Deep GasRoyalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) ReactivatedWell Royalty Exemption; and (iv) Horizontal Re-Entry RoyaltyReduction.  The program being introducedis the Innovative Energy Technologies Program (the “IETP”) which is intended topromote the producers’ investment in research, technology and innovation forthe purposes of improving environmental performance while creating commercialvalue.  The IETP provides royaltyreductions which are presumed to reduce financial risk.  Alberta Energy will be the one to decidewhich projects qualify and the level of support that will be provided.  The deadline for the IETP’s third round ofapplications was May 31, 2007.  Thesuccessful applicants have not yet been announced and it appears, based on theprevious two rounds, that the selection process can take at least 8months.  The technical informationgathered from this program is to be made public once a two-year confidentialityperiod expires.

 

On October 25, 2007, the Alberta governmentreleased a report entitled “The New Royalty Framework” (the “**NRF**”) containing the government’s proposalsfor Alberta’s new royalty regime which is scheduled to be effective on January 1,2009.  The proposed NRF includes newroyalty formulas for conventional oil and natural gas that will operate onsliding scales that are determined by commodity prices and wellproductivity.  Substantial legislative,regulatory and systems updates will be introduced before changes become fullyeffective in January 2009.  See “*Risk Factors – New Alberta Royalty Regime*”.

 

***British Columbia***

*** ***

Producers of oil and natural gas in theProvince of British Columbia are required to pay annual rental payments withrespect to the Crown leases and royalties and freehold production taxes inrespect of oil and gas produced from Crown and freehold lands.  The amount payable as a royalty in respect ofoil depends on the type of oil, the value of the oil, the quantity of oilproduced in a month, and the vintage of the oil.  Generally, the vintage of oil is based on thedetermination of whether the oil is produced from a pool discovered before October 31,1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil),or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take intoaccount the vintage of the oil, if the oil produced has already been sold andany royalty exempt value applicable (exempt wells).  Oil produced from newly discovered pools maybe exempt from the payment of a royalty for the first 36 months of productionor 11,450m3 produced, whichever comes first; and the royaltiesfor third-tier oil are the lowest reflecting the higher costs of explorationand extraction that the producers would incur. The royalty payable on natural gas is determined by a sliding scalebased on a reference price, which is

 

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the greater of the price obtained by theproducer, and a prescribed minimum price. However, when the reference price is below the select price (a parameterused in the royalty rate formula), the royalty rate is fixed.  As an incentive for the production andmarketing of natural gas, which may have been flared, natural gas produced inassociation with oil has a lower royalty then the royalty payable on non-conservationgas.

 

On May 30, 2003, the Ministry of Energyand Mines for the Province of British Columbia announced an Oil and GasDevelopment Strategy for the Heartlands (“Strategy”).  The Strategy is a comprehensive program toaddress road infrastructure, targeted royalties and regulatory reduction, andBritish Columbia service sector opportunities. In addition, the Strategy willresult in economic and employment opportunities for communities in BritishColumbia’s heartlands.

 

Some of the financial incentives in theStrategy include:

 

·                                      Royalty credits of up to $30 million annually towards theconstruction, upgrading, and maintenance of road infrastructure in support ofresource exploration and development. Funding will be contingent upon an equal contribution from industry.

 

·                                      Changes to provincial royalties: new royalty rates for lowproductivity natural gas to enhance marginally economic resources plays,royalty credits for deep gas exploration to locate new sources of natural gas,and royalty credits for summer drilling to expand the drilling season.

 

On February 27, 2007 the Government ofBritish Columbia unveiled the Energy Plan outlining the Province’s strategytowards the environment and which includes targeting for zero net greenhousegas emissions, promoting new investments in innovation, and becoming the world’sleader in sustainable environmental management. For this purpose, on December 18, 2007 proposals were sought forapplications to the Innovation Clean Energy Fund, in order to attract newtechnologies that will helps solve energy and environmental issues.  With regards to the oil and gas industry theobjective is to achieve clean energy through conservation and energy efficientpractices, whilst competitiveness is advocated in order to attract investmentfor the development of the oil and gas sector. Among the changes to beimplemented are: (i) a new Net Profit Royalty Program; (ii) thecreation of a Petroleum Registry; (iii) the establishment of aninfrastructure royalty program (combining roads and pipelines); (iv) the eliminationof routine flaring at producing wells; (v) the creation of policies andmeasures for the reduction of emissions; (vi) the development ofunconventional resources such as tight gas and coalbed gas; and (vii) newthe Oil and Gas Technology Transfer Incentive Program that encourages theresearch, development and use of innovative technologies to increase recoveriesfrom existing reserves and promotes responsible development of new oil and gasreserves.

 

***Saskatchewan***

*** ***

In Saskatchewan, the amount payable as aroyalty in respect of oil depends on the vintage of the oil, the type of oil,the quantity of oil produced in a month, and the value of the oil.  For Crown royalty and freehold production taxpurposes, crude oil is considered “heavy oil”, “southwest designated oil”, or “non-heavyoil other than southwest designated oil”. The conventional royalty and production tax classifications (“fourthtier oil” introduced October 1, 2002, “third tier oil”, “new oil”, or “oldoil”) of oil production are applicable to each of the three crude oiltypes.  The Crown royalty and freeholdproduction tax structure for crude oil is price sensitive and varies betweenthe base royalty rates of 5 per cent for all “fourth tier oil” to 20 per centfor “old oil”.  Marginal royalty ratesare 30 per cent for all “fourth tier oil” to 45 per cent for “old oil”.

 

The amount payable as a royalty in respect ofnatural gas is determined by a sliding scale based on a reference price (whichis the greater of the amount obtained by the producer and a prescribed minimumprice), the quantity produced in a given month, the type of natural gas, andthe vintage of the natural gas.  As anincentive for the production and marketing of natural gas which may have beenflared, the royalty rate on natural gas produced in association with oil isless than on non-associated natural gas. The royalty and production tax classifications of gas production are “fourthtier gas” introduced October 1, 2002, “third tier gas”, “new gas”, and “oldgas”.  The Crown royalty and freeholdproduction tax for gas is price sensitive and varies between the base royaltyrate of 5 per cent for “fourth tier gas” and 20 per cent for “old gas”.  The marginal royalty rates are between 30 percent for “fourth tier gas” and 45 per cent for “old gas”.

 

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On October 1, 2002, the followingchanges were made to the royalty and tax regime in Saskatchewan:

 

·                                             A new Crown royalty and freehold production tax regime applicable toassociated natural gas (gas produced from oil wells) that is gathered for useor sale.  The royalty/tax will be payableon associated natural gas produced from an oil well that exceeds approximately65 thousand cubic metres in a month.

 

·                                             A modified system of incentive volumes and maximum royalty/tax ratesapplicable to the initial production from oil wells and gas wells with afinished drilling date on or after October 1, 2002, was introduced.  The incentive volumes are applicable tovarious well types and are subject to a maximum royalty rate of 2.5 per centand a freehold production tax rate of zero per cent.

 

·                                             The elimination of the re entry and short section horizontal oilwell royalty/tax categories.  Allhorizontal oil wells with a finished drilling date on or after October 1,2002, will receive the “fourth tier” royalty/ tax rates and new incentivevolumes.

 

In 1975, the Government of Saskatchewanintroduced a Royalty Tax Rebate (“RTR”) as a response to the Government ofCanada disallowing crown royalties and similar taxes as a deductible businessexpense for income tax purposes.  As of January 1,2007, the remaining balance of any unused RTR will be limited in its carryforward to five years since the Government of Canada had the initiative toreintroduce the full deduction of provincial resource royalties from federaland provincial taxable income.

 

In June 19, 2007, the Government ofSaskatchewan introduced the Orphan Well and Facility Liability ManagementProgram pursuant to the amendment of the *Oiland Gas Conservation Act* and the *Oiland Gas Conservation Regulations*, 1985.  The program includes a security deposit,which has two purposes: (i) preventing an individual with insufficientfinancial capability from acquiring oil and gas wells or facilities; and (ii) inthe case of a bankrupt company, the funds cover for the decommissioning andreclaiming of orphan property. An additional change introduced is the mandatorylicensing of all upstream oil and gas facilities in Saskatchewan.

 

**LandTenure**

 

Crude oil andnatural gas located in the western provinces is owned predominantly by therespective provincial governments. Provincial governments grant rights to explore for and produce oil andnatural gas pursuant to leases, licences, and permits for varying terms fromtwo years, and on conditions set forth in provincial legislation includingrequirements to perform specific work or make payments.  Oil and natural gas located in such provincescan also be privately owned and rights to explore for and produce such oil andnatural gas are granted by lease on such terms and conditions as may benegotiated.

 

**EnvironmentalRegulation**

 

The oil and natural gas industry is currentlysubject to environmental regulations pursuant to a variety of provincial andfederal legislation.  Such legislationprovides for restrictions and prohibitions on spills, releases or emissions ofvarious substances produced in association with oil and gas industryoperations.  In addition, suchlegislation requires that wells, pipeline and facility sites be operated,maintained, abandoned and reclaimed to the satisfaction of provincialauthorities.  Compliance with suchlegislation can require significant expenditures and a breach of suchrequirements may result in suspension or revocation of necessary licenses andauthorizations, civil liability for pollution damage, and the imposition ofmaterial fines and penalties.

 

Environmental legislation is evolving in amanner expected to result in stricter standards and enforcement, larger finesand liability and potentially increased capital expenditures and operatingcosts.  The discharge of oil, natural gasor other pollutants into the air, soil or water may give rise to liabilities togovernments and third parties and may require our operating entities to incurcosts to remedy such discharge.

 

Environmental legislation in the Province ofAlberta has been consolidated into the *EnvironmentalProtection and Enhancement Act* (Alberta) (the “EPEA”), which cameinto force on September 1, 1993, and the *Oiland Gas Conservation Act* (Alberta) (the “OGCA”).  The EPEA and OGCA impose stricterenvironmental standards, require more stringent compliance, reporting andmonitoring obligations, and significantly increased penalties.  In 2006, the Alberta Government enactedregulations pursuant to the EPEA to specifically target sulphur oxide andnitrous oxide

 

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emissions from industrial operationsincluding the oil and gas industry. In addition, the reduction emissionguidelines outlined in the *Climate Changeand Emissions Management Amendment Act*came into effect on July 1,2007.  Under this legislation, Albertafacilities emitting more than 100,000 tonnes of greenhouse gases a year mustreduce their emissions intensity by 12 per cent.  Industries have three options to choose fromin order to meet the reduction requirements outlined in this legislation, andthese are: (i) by making improvement to operations that result inreductions; (ii) by purchasing emission credits from other sectors orfacilities that have emissions below the 100,000 tonne threshold and arevoluntarily reducing their emission; or (iii) by contributing to theClimate Change and Emissions Management Fund. Industries can either choose one of these options or a combinationthereof.  TheCorporation will be committed to meeting its responsibilities to protect theenvironment wherever it operates and anticipates making increased expendituresof both a capital and an expense nature as a result of the increasinglystringent laws relating to the protection of the environment, and will betaking such steps as required to ensure compliance with the EPEA and similarlegislation in other jurisdictions in which it operates.  The Corporation believes that it is inmaterial compliance with applicable environmental laws and regulations.  The Corporation also believes that it isreasonably likely that the trend towards stricter standards in environmentallegislation and regulation will continue.

 

In January 24, 2008, the Alberta Governmentannounced a new climate change action plan that will cut Alberta’s projected400 million tonnes of emissions in half by 2050. This plan is based on threeareas: (i) carbon capture and storage, which will be mandatory for *in situ* oil sand facilities that use heavyfuels for steam generation; (ii) energy conservation and efficiency; and (iii) greeningproduction through increased investment in clean energy technology, includingsupporting research on new oil sands extraction processes, as well as thefunding of projects that reduce the cost of separating CO2 fromother emissions supporting carbon capture and storage.

 

British Columbia’s *Environmental Assessment Act* became effective June 30,1995.  This legislation rolls theprevious processes for the review of major energy projects into a singleenvironmental assessment process with public participation in the environmentalreview process.

 

In December, 2002, the Government of Canadaratified the Kyoto Protocol (“Protocol”). The Protocol calls for Canada to reduce its greenhouse gas emissions to6 per cent below 1990 “business-as-usual” levels between 2008 and 2012.  Given revised estimates of Canada’s normalemissions levels, this target translates into an approximately 40 per centgross reduction in Canada’s current emissions. It remains uncertain whether the Kyoto target of 6 per cent below 1990emission levels will be enforced in Canada. The Government of Canada has introduced legislation aimed at reducinggreenhouse gas emissions using a “intensity based” approach, the specifics ofwhich have yet to be determined.  BillC-288, which is intended to ensure that Canada meets its global climate changeobligations under the Kyoto Protocol, was passed by the House of Commons on February 14,2007.  On April 26, 2007, theFederal Government released its Action Plan to Reduce Greenhouse Gases and AirPollution (the “Action Plan”) also known as ecoACTION which includes theregulatory framework for air emissions. This Action Plan covers not only large industry, but regulates the fuelefficiency of vehicles and the strengthening of energy standards for a numberof energy using products.  The Governmentof Canada and the Province of Alberta released on January 31, 2008 thefinal report of the Canada-Alberta ecoENERGY Carbon Capture and Storage TaskForce, which recommends among others: (i) incorporating carbon capture andstorage into Canada’s clean air regulations; (ii) allocating new fundinginto projects through competitive process; and targeting research to lower thecost of technology.

 

The Government of Canada and the Province ofAlberta released on January 31, 2008 the final report of theCanada-Alberta ecoENERGY Carbon Capture and Storage Task Force, whichrecommends among others: (i) incorporating carbon capture and storage intoCanada’s clean air regulations; (ii) allocating new funding into projectsthrough competitive process; and targeting research to lower the cost oftechnology.

 

In order to strengthen the Action Plan, on March 10,2008, the Government of Canada released “Turning the Corner – Taking Action toFight Climate Change” (the “**Updated ActionPlan**”) which provides some additional guidance with respect to theGovernment’s plan to reduce greenhouse gas emissions by 20 per cent by 2020 andby 60 per cent to 70 per cent by 2050.

 

The Updated Action Plan is primarily directedtowards industrial emissions from certain specified industries including theoil sands, oil and gas and refining.  TheUpdated Action Plan is intended to create a carbon emissions trading market,including an offset system, to provide incentive to reduce greenhouse gasemission and establish a market price for carbon.  There are mandatory reductions of 18 per centfrom the 2006 baseline starting in 2010 and

 

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an additional 2 per cent in subsequent yearsfor existing facilities. This target will be applied to regulated sectors on afacility-specific, sector-wide or corporate basis; in the case of oils sandsproduction, petroleum refining, natural gas pipelines and upstream oil and gasthe target will be considered facility-specific (sectors in which thefacilities are complex and diverse, or where emissions are affected by factorsbeyond the control of the facility operator). Emissions from new facilities, which are those built between 2004 and2011, will be based on a cleaner fuel standard to encourage continuousemissions intensity reductions over time, and will be granted a 3-year graceperiod during which no emissions intensity targets will apply.  Targets will begin to apply on the fourthyear of commercial operation and the baseline will be the third year’semissions intensity, with a 2 per cent continuous annual emission intensityimprovement required.  The definition ofnew facility also includes greenfield facilities, major expansions constitutingmore than a 25 per cent increase in a facility’s physical capacity, as well astransformations to a facility that involve significant changes to itsprocesses.  For upstream oil and gas andnatural gas pipelines, it will be applied using a sector-specific approach.  For the oil sands, its application will beprocess-specific, oil sands plants built in 2012 and later, those which useheavier hydrocarbons, up-graders and *in-situ*production will have mandatory standards in 2018 that will be basedon carbon capture and storage.

 

In the following regulated sectors, theUpdated Action Plan will apply only to facilities exceeding a minimum annualemissions threshold: (i) 50,000 tonnes of CO2 equivalent peryear for natural gas pipelines; (ii) 3,000 tonnes of CO2equivalent per upstream oil and gas facilities; and (iii) 10,000boe/d/company. These proposed thresholds are significantly stricter than thecurrent Alberta regulatory threshold of 100,000 tonnes of CO2equivalent per year per facility.

 

Four separate compliance mechanisms areprovided in respect of the above targets: Technology Fund contributions, offsetcredits, clean development credits and credits for early action.  The most significant of these compliancemechanisms, at least initially, will be the Technology Fund and for whichregulated entities will be able to contribute in order to comply with emissionsintensity reductions.  The contributionrate will increase over time, beginning at $15 for the 2010-12 period, risingto $20 in 2013, and thereafter increasing at the nominal rate of GDPgrowth.  Contribution limits willcorrespondingly decline from 70 per cent in 2010 to 0 per cent in 2018.  Monies raised through contributions to theTechnology Fund will be used to invest in technology to reduce greenhouse gasemissions.  Alternatively, regulatedentities may be able to receive credits for investing in large-scale andtransformative projects at the same contribution rate and under similarrequirements as mentioned above.

 

The offset system is intended to encourageemissions reductions from activities outside of the regulated sphere, allowingnon-regulated entities to participate in and benefit from emissions reductionactivities.  In order to generate offsetcredits, project proponents must propose and receive approval for emissionsreduction activities that will be verified before offset credits will be issuedto the project proponent.  Those creditscan then be sold to regulated entities for use in compliance or non-regulatedpurchasers that wish to either cancel the offset credits or bank them forfuture use or sale.

 

Under the Updated Action Plan, regulatedentities will also be able to purchase credits created through the CleanDevelopment Mechanism of the Kyoto Protocol. The purchase of such Emissions Reduction Credits will be restricted to10 per cent of each firm’s regulatory obligation, with the added restrictionthat credits generated through forest sink projects will not be available foruse in complying with the Canadian regulations.

 

Finally, a one-time credit of up to 15 Mtworth of emissions credits will be awarded to regulated entities for emissionsreduction activities undertaken between 1992 and 2006.  These credits will be both tradable andbankable**.**

 

Given the evolving nature of the debaterelated to climate change and the control of greenhouse gases and resultingrequirements, it is not currently possible to predict either the nature ofthose requirements or the impact on the Corporation and its operations andfinancial condition at this time.  As thelegislation will be finalized in the fall of 2008 and planned to come intoforce in 2010, the effect on the Trust’s operations cannot be determined atthis time.

 

**RISK FACTORS**

** **

The following is a summary of certain riskfactors relating to the business of the Trust and ARC Resources whichprospective investors should carefully consider before deciding whether topurchase Trust Units or Exchangeable Shares. Residents of the United States and other non-residents of Canada shouldhave additional regard to the risk factors under the heading “Additional RiskFactors Applicable to Residents of the United States and Other Non-Residents ofCanada”.

 

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We are a limited purpose trust and areentirely dependent upon the operations and assets of ARC Resources through ourownership, directly and indirectly, of securities of ARC Resources, includingthe common shares of ARC Resources, the Notes and the Royalties.  Accordingly, our ability to pay distributionsto Unitholders are dependent upon the ability of ARC Resources to meet itsinterest, principal, dividend and other distribution obligations on thesecurities of ARC Resources and to pay the Royalties.  ARC Resources’ income is received from theproduction of oil and natural gas from its Canadian resource properties and issusceptible to the risks and uncertainties associated with the oil and naturalgas industry generally.  If the oil andnatural gas reserves associated with ARC Resources’ resource properties are notsupplemented through additional development or the acquisition of additionaloil and natural gas properties, the ability of ARC Resources to meet itsobligations to us and our ability to pay distributions to Unitholders may beadversely affected.

 

**Volatility ofOil and Natural Gas Prices**

** **

Our operational results and financialcondition, and therefore the amounts we pay to Unitholders, will be dependenton the prices received for oil and natural gas production. Oil and natural gasprices have fluctuated widely during recent years and are determined byeconomic and in the case of oil prices, political factors and a varietyof additional factors beyond our control. These factors include economic conditions, in the United States andCanada, the actions of the Organization of Petroleum Exporting Countries,governmental regulation, political stability in the Middle East and elsewhere,the foreign supply of oil and natural gas, risks of supply disruption, theprice of foreign imports and the availability of alternative fuel sources.  Any substantial and extended decline in theprice of oil and natural gas would have an adverse effect on our carrying valueof our proved and probable reserves, borrowing capacity, revenues, profitabilityand cash flows from operating activities. Any movement in oil and natural gas prices couldhave an effect on our financial condition and therefore on the amounts to bedistributed to our Unitholders.  We maymanage the risk associated with changes in commodity prices by entering intooil or natural gas price hedges.  If wehedge our commodity price exposure, we may forego some of the benefits we wouldotherwise experience if commodity prices were to increase.  In addition, commodity hedging activitiescould expose us to losses.  As at December 31,2007, the Trust balance sheet reflected material unrealized commodity lossesresulting from hedges to protect our commodity risk exposure.  To the extent that we engage in riskmanagement activities related to commodity prices, we will be subject to creditrisks associated with counterparties with which we contract.  For more information in relation to ourhedging program, see “Statement of Reserve Data and Other Oil and GasInformation – Other Oil and Gas Information – Forward Contracts”.

 

Volatile oil and gas prices make it difficult toestimate the value of producing properties for acquisition and often causedisruption in the market for oil and gas producing properties, as buyers andsellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project thereturn on acquisitions and development and exploitation projects.  See “Risk Factors – Purchase of Properties”and “Risk Factors – Project Risks”.

 

**Reserves andResource Estimates**

** **

There are numerous uncertainties inherent inestimating quantities of oil, natural gas and natural gas liquids reserves andresources and the future revenue flows attributed to such reserves, includingmany factors beyond our control.  Ingeneral, estimates of economically recoverable oil and natural gas reserves andresources and the future net revenues therefrom are based upon a number ofvariable factors and assumptions, such as historical production from theproperties, production rates, ultimate reserve recovery, timing and amount ofcapital expenditures, marketability of oil and natural gas, royalty rates, theassumed effects of regulation by governmental agencies and future operatingcosts, all of which may vary materially from actual results.  All such estimates are to some degreespeculative, and classifications of reserves are only attempts to define thedegree of speculation involved.  Forthose reasons, estimates of the economically recoverable oil and natural gasreserves or estimates of resources attributable to any particular group ofproperties, classification of such reserves based on risk of recovery andestimates of future net revenues associated with reserves prepared by differentengineers, or by the same engineers at different times, may vary.

 

Actual production and revenue flows derivedfrom reserves will vary from the reserves estimates contained in the GLJReport, and such variations could be material. The estimates in the GLJ Report are based in part on the timing andsuccess of activities we intend to undertake in future years.  The reserves and estimated future netrevenues to be derived therefrom contained in the GLJ Report will be reduced infuture years to the extent that such activities do not achieve the productionperformance set forth in the GLJ Report.

 

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Thereserves and recovery information contained in the GLJ Report is only anestimate and the actual production and ultimate reserves from the propertiesmay be greater or less than the estimates prepared by GLJ.  The GLJ Report has been prepared using certaincommodity price assumptions which are described in the notes to the reservestables.  If we realize lower prices forcrude oil, natural gas liquids and natural gas and they are substituted for theprice assumptions utilized in those reserves reports, the present value ofestimated future net revenues for our reserves would be reduced and thereduction could be significant, particularly based on the constant price caseassumptions.

 

Estimatesof proved reserves that may be developed and produced in the future aresometimes based upon volumetric calculations and upon analogy to similar typesof reserves rather than actual production history.  Recovery factors and drainage areas wereestimated by experience and analogy to similar producing pools.  Estimates based on these methods aregenerally less reliable than those based on actual production history.  Subsequent evaluation of the same reservesbased upon production history and production practices will result in variationsin the estimated reserves and such variations could be material.

 

**Federal Tax Changes for Income Trusts and Corporations**

** **

Newfederal legislation passed in June 2007, will apply a tax (“SIFT tax”) atthe trust level on distributions of certain income from trusts, such as theTrust, at rates of tax comparable to the combined federal and provincialcorporate tax and will treat such distributions as dividends to theunitholders.  The SIFT tax results inadverse tax consequences to the Trust and certain Unitholders (including mostparticularly Unitholders that are tax deferred or non-residents of Canada) andmay impact distributions from the Trust.

 

Generally,there will be a transition period for an existing trust, such as the Trust, andthe tax under the new legislation will not apply until January 1, 2011.However, the new legislation provides that there are circumstances under whichan existing trust may lose its transitional relief before 2011, including wherethe “normal growth” of a trust existing on October 31, 2006 is exceeded.

 

“Normalgrowth” includes equity growth within certain “safe harbour” limits, measuredby reference to a trust’s market capitalization as of the end of trading on October 31,2006 (which would include only the market value of the trust’s issued andoutstanding publicly-traded trust units, and not any convertible debt, optionsor other interests convertible into or exchangeable for trust units). Thosesafe harbour limits are 40 per cent for the period from November 1, 2006to December 31, 2007, and 20 per cent each for calendar 2008, 2009 and2010. Moreover, these limits are cumulative, so that any unused limit for aperiod carries over into the subsequent period. For ARC the growth limits areapproximately $2.3 billion for 2007 and an additional approximately $1.1billion for each of 2008, 2009 and 2010 with any unused amount rolling forwardto the next year.

 

Whilethe normal growth restrictions are such that it is unlikely they would affectthe Trust’s ability to raise the capital required to maintain and grow itsexisting operations in the ordinary course during the transition period, theycould adversely affect the cost of raising capital and the Trust’s ability toundertake more significant acquisitions. The SIFT tax has reduced the value of the Trust Units, which hasincreased the cost to the Trust of raising capital in the public capitalmarkets. In addition management of ARC Resources believes that the SIFTtax:  (a) substantially eliminatesthe competitive advantage that the Trust and other Canadian energy trustsenjoyed relative to their corporate peers in raising capital in a tax-efficientmanner, and (b) places the Trust and other Canadian energy trusts at acompetitive disadvantage relative to industry competitors, including U.S.master limited partnerships, which will continue to not be subject to entitylevel taxation. The new legislation also makes the Trust Units less attractiveas an acquisition currency. As a result, it may become more difficult for theTrust to compete effectively for acquisition opportunities. There can be noassurance that the Trust will be able to reorganize its legal and tax structureto substantially mitigate the expected impact of the SIFT tax.

 

Noassurance can be provided that the SIFT tax will not apply to the Trust prior toJanuary 1, 2011, or that the legislation will not be further changed in amanner which affects the Trust and its Unitholders.  See “Risk Factors – Changes in Legislation”.

 

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**Operational Matters**

** **

Acquiring,developing and exploring for oil and natural gas involves many risks, whicheven a combination of experience, knowledge and careful evaluation may not beable to overcome.  These risks include,but are not limited to, encountering unexpected formations or pressures,premature declines of reservoirs, blow-outs, equipment failures and otheraccidents, sour gas releases, uncontrollable flows of oil, natural gas or wellfluids, adverse weather conditions, pollution, other environmental risks, firesand spills.  Although we maintaininsurance in accordance with customary industry practice, we are not fullyinsured against all of these risks. Losses resulting from the occurrence of these risks could have amaterial adverse impact on us.  Likeother oil and natural gas trusts and companies, we attempt to conduct ourbusiness and financial affairs so as to protect against political and economicrisks applicable to operations in the jurisdictions where we operate but therecan be no assurance that we will be successful in so protecting our assets.

 

Continuingproduction from a property, and to some extent the marketing of productiontherefrom, are largely dependent upon the ability of the operator of theproperty.  Operating costs on mostproperties have increased steadily over recent years.  To the extent the operator fails to performthese functions properly, operating income may be reduced. Payments fromproduction generally flow through the operator and there is a risk of delay andadditional expense in receiving such revenues if the operator becomesinsolvent.  A reduction of the incomeavailable for distributions could result in such circumstances.

 

**Regulatory**

** **

Oil and naturalgas operations (exploration, production, pricing, marketing and transportation)are subject to extensive controls and regulations imposed by various levels ofgovernment, which may be amended from time to time.  Governments may regulate or intervene withrespect to price, taxes, royalties and the exportation of oil and naturalgas.  Such regulations may be changedfrom time to time in response to economic or political conditions.  The implementation of new regulations or themodification of existing regulations affecting the oil and natural gas industrycould reduce demand for natural gas and crude oil and increase our costs, anyof which may have a material adverse effect on our business, financialcondition and results of operations.  Inorder to conduct oil and gas operations, we will require licenses from variousgovernmental authorities.  There can beno assurance that we will be able to obtain all of the licenses and permitsthat may be required to conduct operations that it may wish to undertake.  See “Industry Regulations”.

 

**Variations in Interest Rates and Foreign Exchange Rates**

** **

Anincrease in interest rates could result in a significant increase in the amountwe pay to service debt, resulting in a decrease in distributions toUnitholders, as well as impact the market price of the Trust Units.

 

Worldoil prices are quoted in Unites States dollars and the price received byCanadian producers is therefore affected by the Canadian/U.S. dollar exchangerate that may fluctuate over time.  Amaterial increase in the value of the Canadian dollar may negatively impact ournet production revenue.

 

Inaddition, the exchange rate for the Canadian dollar versus the U.S. dollar hasincreased significantly over the last 12 months, resulting in our receipt offewer Canadian dollars for our production which may affect futuredistributions.  We have initiated certainhedges to attempt to mitigate these risks. If we hedge interest rates or foreign exchange rates we may forego someof the benefits we would otherwise experience if interest rates decreased or theCanadian dollar depreciated.  In addition,these hedging activities could expose us to losses.  To the extent that we engage in riskmanagement activities related to foreign exchange rates and interest rates, itwill be subject to credit risk associated with counterparties with which wecontract.  The increase in the exchangerate for the Canadian dollar and future Canadian/United States exchange rateswill impact future distributions and the future value of our reserves asdetermined by independent evaluators.

 

**New Alberta Royalty Regime**

** **

On October 25,2007, the Alberta government released a report entitled “The New RoyaltyFramework” (“NRF”) containing the government’s proposals for Alberta’s newroyalty regime which is scheduled to be effective on January 1, 2009.  Given the lack of clarity in the finaldetails of the NRF, the fact that changes are still being 

 

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contemplated bythe government to mitigate some of the initial impact and that future commodityprices and well productivity are unknown, it is not possible at this time todetermine the full impact of the NRF on our financial condition and operationsand in particular the extent to which the NRF will reduce our cash flow fromoperating activities, which will in turn reduce the cash otherwise availablefor distribution by us to our Unitholders. Approximately two-thirds of our reserves are located in the Province ofAlberta.

 

We cannot provideany assurance that the NRF will be implemented in the form proposed.  If changes are made to the NRF before it isimplemented by the Alberta government, such changes could result in theimplementation of a new royalty regime that impacts us in a materiallydifferent manner, and that is more adverse to us, than the NRF as currentlyproposed.  See “Risk Factors – Changes inLegislation”.

 

**Purchase of Properties**

** **

Theprice we pay for the purchase of the properties is based on engineering andeconomic estimates of the reserves made by independent engineers modified toreflect our technical and economic views. These assessments include a number ofmaterial assumptions regarding such factors as recoverability and marketabilityof oil, natural gas, natural gas liquids and sulphur, future prices of oil,natural gas, natural gas liquids and sulphur and operating costs, futurecapital expenditures and royalties and other government levies which will beimposed over the producing life of the reserves. Many of these factors aresubject to change and are beyond our control and the control of the operatorsof the properties.  In particular,changes in the prices of and markets for petroleum, natural gas, natural gasliquids and sulphur from those anticipated at the time of making suchassessments will affect the amount of future distributions and as such thevalue of the Trust Units. In addition, all such estimates involve a measure ofgeological and engineering uncertainty which could result in lower productionand reserves than attributed to the properties. Actual reserves could vary materially from these estimates.  Consequently, the reserves acquired may beless than expected, which could adversely impact cash flow from operatingactivites and distributions to Unitholders. See “ARC Energy Trust – General Development of the Business”.

 

**Enhanced Oil Recovery**

** **

We believeour ownership of our assets in Redwater and North Pembina Cardium Unit #1strategically positions us for participation in properties with large reservesof unrecovered original resources in place which may be amenable to secondaryrecovery techniques such as carbon dioxide (“CO2”) miscible orimmiscible flooding.  The implementationof secondary oil recovery techniques on properties like Redwater or the PembinaCardium Unit #1 are subject to significant risk factors, including therequirements of long term supply agreements for CO2 and large scaleinfrastructure investments.  We have justbegun to devote resources to the study of such matters and no reserves arereflected in the GLJ Report for any of these secondary recovery techniques.  There is no assurance as to when or if suchsecondary recovery techniques will be implemented, or if implemented, when orif such secondary recovery techniques would be successful.

 

Currently,companies are permitted to emit CO2 into the atmosphere with norequirement to capture and re-inject the emissions.  In order for ARC Resources to carry out itsenhanced oil recovery program it is necessary to obtain CO2 at acost effective rate.  Given thatcompanies are not forced to capture their emissions, the infrastructure has notbeen put in place to facilitate this process. Under the current regulatory environment, the economic parameters of theTrust’s enhanced oil recovery programs would be limited.  For more information, see “Risk Factors –Environmental Concerns”.

 

**Project Risks**

** **

We will manage avariety of small and large projects in the conduct of its business.  Project delays may delay expected revenuesfrom operations.  Significant projectcost over-runs could make a project uneconomic. Our ability to execute projects and market oil and natural gas willdepend upon numerous factors beyond our control, including:

 

·                  the availability of processingcapacity;

 

·                  the availability and proximity ofpipeline capacity;

 

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·                  the availability of storagecapacity;

 

·                  the supply of and demand for oiland natural gas;

 

·                  the availability of alternativefuel sources;

 

·                  the effects of inclement weather;

 

**·**                 the availability of drilling and relatedequipment;

 

·                  unexpected cost increases;

 

·                  accidental events;

 

·                  changes in regulations;

 

·                  the availability and productivityof skilled labour; and

 

·                  the regulation of the oil andnatural gas industry by various levels of government and governmental agencies.

 

Because of thesefactors, we could be unable to execute projects on time, on budget or at all,and may not be able to effectively market the oil and natural gas that itproduces.

 

**Changes in Legislation**

** **

Incometax laws, or other laws or government incentive programs relating to the oiland gas industry, such as the treatment of mutual fund trusts and resourcetaxation, may in the future be changed or interpreted in a manner thatadversely affects us and our Unitholders. Tax authorities having jurisdiction over us or Unitholders may disagreewith how we calculate our income for tax purposes or could changeadministrative practises to our detriment or the detriment of Unitholders.

 

Weintend to continue to qualify as a mutual fund trust for purposes of the TaxAct.  We may not, however, always be ableto satisfy any future requirements for the maintenance of mutual fund truststatus.  Should our status as a mutualfund trust be lost or successfully challenged by a relevant tax authority,certain adverse consequences may arise for us and Unitholders.  Some of the significant consequences oflosing mutual fund trust status are as follows:

 

·              We would be taxed on certain types of income distributed toUnitholders, including income generated by the Royalties held by us.  Payment of this tax may have adverseconsequences for some Unitholders, particularly Unitholders that are notresidents of Canada and residents of Canada that are otherwise exempt fromCanadian income tax.

 

·              We would cease to be eligible for the capital gains refund mechanismavailable under Canadian tax laws if it ceased to be a mutual fund trust.

 

·              Trust Units held by Unitholders that are not residents of Canadawould become taxable Canadian property. These non-resident holders would be subject to Canadian income tax onany gains realized on a disposition of Trust Units held by them.

 

·              Trust Units would not constitute qualified investments forregistered retirement savings plans (“RRSPs”), registered retirement incomefunds (“RRIFs”), registered education savings plans (“RESTs”) or deferredprofit sharing plans (“DPSPs”).  If, atthe end of any month, one of these exempt plans holds Trust Units that are notqualified investments, the plan must pay a tax equal to one per cent of thefair market value of the Trust Units at the time the Trust Units were acquiredby the exempt plan.  An RRSP or RRIFholding non-qualified Trust Units would be subject to taxation on incomeattributable to the Trust Units.  If anRESP holds non-qualified Trust Units, it may have its registration revoked bythe Canada Revenue Agency.

 

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Inaddition, we may take certain measures in the future to the extent we believenecessary to ensure that we maintain the status as a mutual fund trust.  These measures could be adverse to certainholders of Trust Units, particularly non-residents of Canada as defined in theTax Act.

 

Formore information, see “Risk Factors – Non-resident Ownership of Trust Units”, “RiskFactors – Federal Tax Changes for Income Trusts and Corporations”, “RiskFactors – Environmental Concerns”, and “Industry Regulations – Environmental Regulation”.

 

**Maintenance of Distributions**

** **

Weconduct limited exploration activities for oil and natural gas reserves.  Instead, we add to our oil and natural gasreserves primarily through development and acquisitions.  As a result, future oil and natural gasreserves are highly dependent on our success in exploiting existing propertiesand acquiring additional reserves.  Wealso distribute the majority of our cash flow from operating activities toUnitholders rather than reinvesting it in reserves additions.  Accordingly, if external sources of capital,including the issuance of additional Trust Units, become limited or unavailableon commercially reasonable terms, our ability to make the necessary capitalinvestments to maintain or expand its oil and natural gas reserves may beimpaired.  To the extent that we use cashflow from operating activities to finance capital expenditures or propertyacquisitions, the level of cash flow from operating activities available fordistribution to Unitholders will be reduced. Additionally, we cannot guarantee that we will be successful indeveloping additional reserves or acquiring additional reserves on terms thatmeet our investment objectives.  Withoutthese reserves additions, our reserves will deplete and as a consequence,either production from, or the average reserves life of, our properties willdecline. Either decline may result in a reduction in the value of Trust Unitsand in a reduction in cash flow from operating activities available fordistributions to Unitholders.

 

**Expansion of Operations**

** **

Ouroperations and expertise are currently focused on conventional oil and gasproduction and development in the Western Canadian Sedimentary Basin.  In the future, we may acquire oil and gasproperties outside this geographic area. In addition, the Trust Indenture does not limit our activities to oiland gas production and development, and we could acquire other energy relatedassets, such as oil and natural gas processing plants or pipelines, or aninterest in an oil sands project. Expansion of our activities into new areas may present new additionalrisks or alternatively, significantly increase the exposure to one or more ofthe present risk factors which may adversely affect our future operational andfinancial conditions.

 

**Failure to Realize Anticipated Benefits of Acquisitions andDispositions**

** **

We makeacquisitions and dispositions of businesses and assets in the ordinary courseof business.  Achieving the benefits ofacquisitions depends in part on successfully consolidating functions andintegrating operations and procedures in a timely and efficient manner as wellas our ability to realize the anticipated growth opportunities and synergiesfrom combining the acquired businesses and operations with those of the Trust.  The integration of acquired business mayrequire substantial management effort, time and resources and may divertmanagement’s focus from other strategic opportunities and operationalmatters.  Management continually assessesthe value and contribution of services provided and assets required to providesuch services.  In this regard, non-coreassets are periodically disposed of, so that we can focus its efforts andresources more efficiently.  Depending onthe state of the market for such non-core assets, certain of our non-coreassets, if disposed of, could realize less than their carrying value on ourfinancial statements.

 

**Non-resident Ownership of Trust Units**

** **

TheTrust intends to comply with the requirements under the Tax Act for “unittrusts” and “mutual fund trusts” at all relevant times such that we maintainour status of a unit trust and a mutual fund trust for purposes of the TaxAct.  In this regard, we may, from timeto time, among other things, take all necessary steps to monitor the activitiesof the Trust and ownership of the Trust Units. If at any time we become aware that the activities of the Trust andownership of the Trust Units by non-residents (non-residents of Canada andpartnerships) may threaten the status of the Trust under the Tax Act as a “unittrust” or “mutual fund trust”, we are authorized to take such action as may benecessary in the opinion of ARC Resources to maintain the status of the Trustas a unit trust and a mutual fund trust,

 

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includingthe imposition of restrictions on the issuance by the Trust, or the transfer byany Unitholder, of Trust Units to a non resident. See “Limitations onNon-Resident Ownership” and “Risk Factors – Change of Legislation”.

 

**Environmental Concerns**

** **

Theoil and natural gas industry is subject to environmental regulation pursuant tolocal, provincial and federal legislation. A breach of such legislation may result in the imposition of fines orissuance of clean up orders in respect of us or our properties. Suchlegislation may be changed to impose higher standards and potentially morecostly obligations on us.  Furthermore,management believes the political climate appears to favour new programs for environmentallaws and regulation, particularly in relation to the reduction of emissions,and there is no assurance that any such programs, laws or regulations, ifproposed and enacted, will not contain emission reduction targets which wecannot meet, and financial penalties or charges could be incurred as a resultof the failure to meet such targets.  Inparticular there is uncertainty regarding the Government of Canada’s Clean AirAct of 2006.  The Clean Air Act proposesto reduce greenhouse gas emissions, however emission targets and compliancedeadlines differ from those outlined in the Kyoto Protocol which was ratifiedby Canada.  If passed, the Clean Air Actmay have adverse operational and financial implications to the Trust.  See “Industry Regulations – EnvironmentalRegulation”.  Although we haveestablished a reclamation fund for the purpose of funding our currentlyestimated future environmental and reclamation obligations based on our currentknowledge, there can be no assurance that we will be able to satisfy our actualfuture environmental and reclamation obligations.

 

Provincialemission reduction requirements, such as those proposed in Alberta’s Bill 37Climate Change and Emissions Management, may require the reduction of emissionsor emissions intensity of our operations and facilities.  The direct or indirect costs of theseregulations may adversely and materially affect our business.

 

Canadais a signatory to the United Nations Framework Convention on Climate Change andin December 2002 the Government of Canada ratified the Kyoto Protocol andit became legally binding on February 16, 2005.  This protocol calls for Canada to reduce itsgreenhouse gas emissions to six per cent below 1990 levels during the periodbetween 2008 and 2012.  Our explorationand production facilities and other operations and activities emit greenhousegases that may subject us to legislation regulating emissions of greenhousegases.  The Government of Canada has putforward a Climate Change Plan for Canada which suggests further legislationwill set greenhouse gases emission reduction requirements for variousindustrial activities, including oil and gas exploration and production.  There has been much public debate withrespect to Canada’s ability to meet these targets and the Government’s strategyor alternative strategies with respect to climate change and the control ofgreenhouse gases.  Implementation ofstrategies for reducing greenhouse gases whether to meet the limits required bythe Kyoto Protocol or as otherwise determined, could have a material impact onthe nature of oil and natural gas operations, including ours.  Given the evolving nature of the debaterelated to climate change and the control of greenhouse gases and resultingrequirements, it is not possible to predict either the nature of those requirementsor the impact on us and our operations and financial condition.  See “Risk Factors –Change of Legislation”.

 

On March 10,2008, the Government of Canada released “Turning the Corner – Taking Action toFight Climate Change” (the “Updated Action Plan”) which provides someadditional guidance with respect to the Government of Canada’s plan to reducegreenhouse gas emissions by 20 per cent by 2020 and by 60 per cent to 70 percent by 2050.  The Updated Action Plan isprimarily directed towards industrial emissions from certain specifiedindustries including the oil sands, oil and gas and refining industries.  The Updated Action Plan is intended to forceindustry to reduce greenhouse gas emissions and to create a carbon emissionstrading market, including an offset system, to provide incentive to reducegreenhouse gas emission and establish a market price for carbon.  The Updated Action Plan provides for: (i) mandatoryreductions of 18 per cent from the 2006 baseline starting in 2010 and by anaddition 2 per cent in subsequent years for existing facilities; (ii) newfacilities built between 2004 and 2011 will have mandatory emissions standardsbased upon clean fuel standards (natural gas) with a 2 per cent reduction belowthe third years intensity levels; and (iii) oil sands plants built in 2012and later which use heavier hydrocarbons and upgraders and in situ productionwill have mandatory standards in 2018 based carbon capture and storage or othergreen technologies intensity.  For theupstream oil and gas industry the Updated Action Plan also provides for acompany threshold of 10,000 boe/day and facility threshold of 3,000 tonnes ofC02.

 

Althoughwe believe that we are in material compliance with current applicableenvironmental regulations, no assurance can be given that environmental lawswill not result in a curtailment of production or a material increase in thecosts of production, development or exploration activities or otherwiseadversely affect our financial condition, results of operations orprospects.  Future changes in otherenvironmental legislation could occur and 

 

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resultin stricter standards and enforcement, larger fines and liability, andincreased capital expenditures and operating costs, which could have a materialadverse effect on our financial condition or results of operations.  See “Industry Conditions – EnvironmentalRegulation”.

 

**Additional Financing**

** **

Inthe normal course of making capital investments to maintain and expand our oiland gas reserves additional Trust Units are issued from treasury which mayresult in a decline in production per Trust Unit and reserves per TrustUnit.  In addition, there may be periodswhere we borrow to finance significant acquisitions or development projects inorder to accomplish our long term objectives, which may increase our debtsubstantially beyond an optimal capital structure.  To the extent that external sources ofcapital, including the issuance of additional Trust Units become limited orunavailable, our ability to make the necessary capital investments foracquisitions or development projects to maintain or expand our oil and gasreserves may be impaired, along with the ability to repay or refinance anyprior borrowings.  Management believesthat SIFT tax imposed by the Government of Canada will substantially eliminatethe competitive advantage that we and other energy trusts have enjoyed relativeto our industry competitors in raising capital in a tax-efficient manner.  See “Risk Factors – Federal Tax Changes toIncome Trusts and Corporations”.  To theextent that we are required to use cash flow from operating activities tofinance capital expenditures or property acquisitions or to pay debt servicecharges or to reduce debt, the level of cash flow from operating activitiesavailable for distribution to Unitholders will be reduced.

 

**Competition**

** **

Thereis strong competition relating to all aspects of the oil and gas industry.  There are numerous trusts in the oil and gasindustry, who are competing for the acquisitions of properties with longer lifereserves, properties with exploitation and development opportunities andundeveloped land.  As a result of suchcompetition, it may be more difficult to acquire reserves on beneficial terms.  We also compete for reserves acquisitions andundeveloped land with a substantial number of other oil and gas companies, manyof which have significantly greater financial and other resources than we do.

 

TheTrust competes with other oil and gas entities to hire and retain skilledpersonnel necessary for running of daily operations of the Trust including theexecution of the annual capital development program.  The inability to hire and retain skilledpersonnel could adversely impact certain operational and financial results ofthe Trust.

 

**Accounting Write-Downs as a Result of GAAP**

** **

CanadianGenerally Accepted Accounting Principles (“GAAP”) require that management applycertain accounting policies and make certain estimates and assumptions whichaffect reported amounts in our consolidated financial statements.  The accounting policies may result innon-cash charges to net income and write-downs of net assets in the financialstatements. Such non-cash charges and write-downs may be viewed unfavourably bythe market and may result in an inability to borrow funds and/or may result ina decline in the Trust Unit price.

 

UnderGAAP, the net amounts at which petroleum and natural gas costs on a property orproject basis are carried are subject to a cost-recovery test which is based inpart upon estimated future net revenues from reserves. If net capitalized costsexceed the estimated recoverable amounts, we will have to charge the amounts ofthe excess to earnings.  A decline in thenet value of oil and natural gas properties could cause capitalized costs toexceed the cost ceiling, resulting in a charge against earnings.  The net value of oil and gas properties arehighly dependent upon the prices of oil and natural gas.  See “Risk Factors – Volatility of Oil andNatural Gas Prices”.

 

GAAPrequires that goodwill balances be assessed at least annually for impairmentand that any permanent impairment be charged to net income. A permanentreduction in reserves, decline in commodity prices, and/or reduction in the TrustUnit price may indicate goodwill impairment. As at December 31, 2007 wehad $157.6 million recorded on its balance sheet as goodwill arising out of ouracquisition of Star Oil & Gas Ltd. in 2003.  An impairment would result in a write-down ofthe goodwill value and a non-cash charge against net income. The calculation ofimpairment value is subject to management estimates and assumptions.

 

NewGAAP surrounding accounting for derivatives may result in non-cash chargesagainst net income as a result of changes in the fair market value ofderivative instruments. A decrease in the fair market value of the derivative 

 

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instrumentsas the result of fluctuations in commodity prices and foreign exchange rates mayresult in a write-down of net assets and a non-cash charge against net income.Such write-downs and non-cash charges may be temporary in nature if the fairmarket value subsequently increases.

 

**Debt Service**

** **

Amountspaid in respect of interest and principal on debt incurred in respect of theproperties will reduce royalty income. Variations in interest rates and scheduled principal repayments couldresult in significant changes in the amount required to be applied to debtservice before payment of the Royalties and interest on the Long Term Notes anddistributable income.  Certain covenantsof the agreements with our lenders may also limit distributions to us from oursubsidiaries.  Although we believe thecredit facilities will be sufficient for our immediate requirements, there canbe no assurance that the amount will be adequate for our future financialobligations or that additional funds will be able to be obtained.  For more information, see “Other InformationRelating To Our Business – Borrowing”.

 

Thelenders have or will be provided with security over substantially all of ourassets.  If we become unable to pay ourdebt service charges or otherwise commit an event of default such asbankruptcy, the lender may foreclose on or sell the properties free from ortogether with the Royalties.  The paymentof interest and principal on debt may also result in us having taxable incomeand cash taxes payable as taxable income would no longer be reduced by royaltypayments at the time debt repayment occurs.

 

**Delay in Distributions**

** **

Inaddition to the usual delays in payment by purchasers of oil and natural gas tothe operators of the properties, and by the operator to us, payments betweenany of such parties may also be delayed by restrictions imposed by lenders,delays in the sale or delivery of products, delays in the connection of wellsto a gathering system, blowouts or other accidents, recovery by the operator ofexpenses incurred in the operation of the properties or the establishment bythe operator of reserves for such expenses.

 

**Reliance on Key Members of Management**

** **

Oursuccess depends on large measure on certain key personnel.  The loss of such key personnel could delaythe completion of certain projects or otherwise have a material adverse effecton us.  Unitholders will be dependent onour management in respect of the administration and management of all mattersrelating to our properties, the Royalties and Trust Units.  As of December 31, 2007, we operatedapproximately 75 per cent of the total daily production of our properties.  Investors who are not willing to rely on ourmanagement should not invest in Trust Units.

 

**Depletion of Reserves**

** **

Distributionsof distributable income in respect of properties, absent commodity priceincreases or cost effective acquisition and development activities, willdecline over time in a manner consistent with declining production from typicaloil, natural gas and natural gas liquids reserves.  We will not be reinvesting cash flow fromoperating activities in the same manner as other industry participants as weconduct only minimal exploratory activities; nor to the same extent as otherindustry participants as one of our main objectives is to maximize long-termdistributions.  Accordingly, absentcapital injections, our initial production levels and reserves may decline andthe level of distributable income will be reduced.

 

Ourfuture oil and natural gas reserves and production, and therefore our cashflows from operating activities, will be highly dependent on our success inexploiting our reserves base and acquiring additional reserves. Withoutreserves additions through acquisition or development activities, our reservesand production may decline over time as reserves are produced.

 

Tothe extent that external sources of capital, including the issuance ofadditional Trust Units become limited or unavailable, our ability to make thenecessary capital investments to maintain or expand our oil and natural gasreserves will be impaired.  To the extentthat we are required to use cash flow from operating activities to financecapital expenditures or property acquisitions, the level of distributableincome will be reduced.

 

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There can beno assurance that we will be successful in developing or acquiring additionalreserves on terms that meet our investment objectives.

 

**Net AssetValue**

** **

The net asset value of our assets from timeto time will vary dependent upon a number of factors beyond the control ofmanagement, including oil and gas prices. The trading prices of the Trust Units from time to time is alsodetermined by a number of factors which are beyond the control of managementand such trading prices may be greater than the net asset value of our assets.

 

**Return ofCapital**

** **

Trust Units will have no value when reservesfrom the properties can no longer be economically produced and, as a result,distributions do not represent a “yield” in the traditional sense and are not comparableto bonds or other fixed yield securities, where investors are entitled to afull return of the principal amount of debt on maturity in addition to a returnon investment through interest payments. Distributions represent a blend of return of Unitholders initialinvestment and a return on Unitholders initial investment.

 

Unitholders have a limited right to require arepurchase of their Trust Units, which is referred to as a redemptionright.  See “Our Information – Rightof Redemption.”  It is anticipated thatthe redemption right will not be the primary mechanism for Unitholders toliquidate their investment.  The right toreceive cash in connection with a redemption is subject to limitations.  Any securities which may be distributed *in specie* to Unitholders in connectionwith a redemption may not be listed on any stock exchange and a market may notdevelop for such securities.  Inaddition, there may be resale restrictions imposed by law upon the recipients ofthe securities pursuant to the redemption right.

 

**Nature ofTrust Units**

** **

The Trust Units do not represent atraditional investment in the oil and natural gas sector and should not beviewed by investors as shares in ARC Resources. The Trust Units represent afractional interest in the Trust.  Corporate law does not govern the Trust andthe rights of Unitholders.  As holders ofTrust Units, Unitholders will not have the statutory rights normally associatedwith ownership of shares of a corporation including, for example, the right tobring oppression or derivative actions. The rights of Unitholders are specifically set forth in the TrustIndenture.  In addition, trusts are notdefined as recognized entities within the definitions of legislation such asthe *Bankruptcy and Insolvency Act*(Canada), the *Companies’ CreditorsArrangement Act* (Canada) and in some cases the *Winding Up and Restructuring Act*(Canada).  As a result, in the event ofan insolvency or restructuring, a Unitholder’s position as such may be quitedifferent than that of a shareholder of a corporation.  The Trust’s sole assets will be the royaltyand other investments in securities. The price per Trust Unit is a function ofanticipated distributable income, the properties acquired by us and our abilityto effect long-term growth in our value. The market price of the Trust Units will be sensitive to a variety ofmarket conditions including, but not limited to, interest rates and our abilityto acquire suitable oil and natural gas properties. Changes in marketconditions may adversely affect the trading price of the Trust Units.

 

**The Trust Units arenot “deposits” within the meaning of the Canada Deposit Insurance CorporationAct (Canada) and are not insured under the provisions of that Act or any otherlegislation.  Furthermore, we are not atrust company and, accordingly, are not registered under any trust and loancompany legislation as we do not carry on or intend to carry on the business ofa trust company.**

 

**UnitholderLimited Liability**

** **

The Trust Indenture provides that no Unitholderwill be subject to any liability in connection with us or our obligations andaffairs and, in the event that a court determines Unitholders are subject toany such liabilities, the liabilities will be enforceable only against, andwill be satisfied only out of our assets. Pursuant to the Trust Indenture, wewill indemnify and hold harmless each Unitholder from any costs, damages,liabilities, expenses, charges and losses suffered by a Unitholder resultingfrom or arising out of such Unitholder not having such limited liability.

 

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The Trust Indenture provides that all writteninstruments signed by or on behalf of the Trust must contain a provision to theeffect that such obligation will not be binding upon Unitholders personally.The principal investment of the Trust is the royalty agreements which containsuch provisions.  Personal liability mayalso arise in respect of claims against the Trust that do not arise undercontracts, including claims in tort, claims for taxes and possibly certainother statutory liabilities.  Thepossibility of any personal liability of this nature arising is consideredunlikely.  The *Income Trusts Liability Act* (Alberta) came into force on July 1,2004.  The legislation provides that aunitholder will not be, as a beneficiary, liable for any act, default,obligation or liability of the trustee that arises after the legislation cameinto force.

 

Our operations will be conducted, upon theadvice of counsel, in such a way and in such jurisdictions as to avoid as faras possible any material risk of liability on Unitholders for claims againstthe Trust.

 

**Titleto Properties**

** **

Our properties are held in theform of licenses and leases and working interests in licenses and leases.  If we or the holder of the license or leasefails to meet the specific requirement of a license or lease, the license orlease may terminate or expire.  There canbe no assurance that any of the obligations required to maintain each licenseor lease will be met.  The termination orexpiration of a license or lease or the working interest relating to a licenseor lease may have a material adverse affect on our results of operations andbusiness.

 

Aboriginal peoples have claimed aboriginal title andrights to portions of western Canada.  Weare not aware that any claims have been made in respect of its properties andassets; however, if a claim arose and was successful this could have an adverseeffect on us and our operations.

 

Although satisfactory title reviews aregenerally conducted in accordance with industry standards, such reviews do notguarantee or certify that a defect in the chain of title may not arise todefeat our claim to certain properties. In certain situations there may be multiplemineral resource owners claiming various ownership over the same parcel ofland.  Any settlement of a dispute ofownership may result in the forfeiture of the mineral resource by us or thepayment of cash compensation to the mineral resource owner.

 

**AdditionalRisk Factors Applicable to Residents of the United States and OtherNon-Residents of Canada**

** **

***Limited Ability of Residents in the United States to Enforce CivilRemedies***

*** ***

Both ARC and ARC Resources are organizedunder the laws of Alberta, Canada and have their principal place of business inCanada.  Most of our directors and all ofour officers and the representatives of the experts who provide services to us(such as its auditors and its independent reserve engineers), and all of ourassets and all or a substantial portion of the assets of such persons arelocated outside the United States.  As aresult, it may be difficult for investors in the United States to effectservice of process within the United States upon such directors, officers andrepresentatives of experts who are not residents of the United States or toenforce against them judgements of the United States courts based upon civilliability under the United States federal securities laws or the securitieslaws of any state within the United States. There is doubt as to the enforceability in Canada against ARC or ARCResources or against any of our directors, officers or representatives ofexperts who are not residents of the United States, in original actions or inactions for enforcement of judgements of United States courts of liabilitiesbased solely upon the United States federal securities laws or securities lawsof any state within the United States.

 

***Differences in Reporting Practices in Canada and the United States***

*** ***

We report our production and reservequantities in accordance with Canadian practices and specifically in accordancewith NI 51-101.  These practices aredifferent from the practices used to report production and to estimate reservesin reports and other materials filed with the SEC by companies in the UnitedStates.

 

We incorporate additional information withrespect to production and reserves which is either not generally included orprohibited under rules of the SEC and practices in the United States.  We follow the Canadian practice of reportinggross production and reserve volumes; however, we also follows the UnitedStates practice of separately reporting these volumes on a net basis (after thededuction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costswhen we estimate our reserves; however, we separately estimate 

 

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our reserves using prices and costs heldconstant at the effective date of the reserve report.  These requirements are similar to theconstant pricing reserve methodology utilized in the United States.

 

We included in this Annual Information Form estimatesof proved and proved plus probable reserves. The SEC generally prohibits the inclusion of estimates of probablereserves in filings made with it.  Thisprohibition does not apply to us because we are a Canadian foreign privateissuer.

 

***Additional Taxation Applicable to Non Residents***

*** ***

The Tax Act and the tax treaties betweenCanada and other countries may impose additional withholding or other taxes onthe cash distributions or other property paid by us to Unitholders who are NonResidents of Canada, and these taxes may change from time to time.  Since January 1, 2005, a 15 per centCanadian withholding tax is applied to the return of capital portion ofdistributions made to Non Resident Unitholders.

 

Additionally, the reduced “Qualified Dividend”rate of 15 per cent tax applied to our distributions under current U.S. taxlaws is scheduled to expire at the end of 2010 and there is no assurance thatthis reduced tax rate will be renewed by the U.S.  government at such time.

 

Furthermore, it is anticipated that theimplementation of the SIFT tax may have tax consequences for Non Residents ofCanada that are more adverse than the tax consequences to other classes ofUnitholders.

 

***Foreign Exchange Risk of Non Resident Unitholders***

*** ***

Our distributions are declared in Canadiandollars and converted to foreign denominated currencies at the spot exchangerate at the time of payment.  As aconsequence, investors are subject to foreign exchange risk.  To the extent that the Canadian dollarstrengthens with respect to their currency, the amount of the distribution willbe reduced when converted to their home currency.

 

**TRANSFER AGENTS ANDREGISTRARS**

** **

The transfer agent and registrar for theTrust Units and the Exchangeable Shares is Computershare Trust Company ofCanada at its principal offices in Calgary and Toronto.

 

**MATERIAL CONTRACTS**

** **

The following comprises particulars of everymaterial contract to the Trust that was entered into within the most recentlycompleted financial year, or entered into before the most recently completedfinancial year which is still in effect, other than a contract entered into inthe ordinary course of business:

 

1.                                       Trust Indenture.  Forinformation, see “Our Information” and “Corporate Governance”.

 

2.                                       Exchangeable Share Provisions. For information, see “Share Capital of ARC Resources - ExchangeableShares”.

 

3.                                       Exchangeable Share Voting and Exchange Trust Agreement dated January 31,2001 among the trust, 908563 Alberta Ltd. (the predecessor to ARC Subco) ARCResources and Computershare Trust Company of Canada, as amended.  For information, see “Share Capital of ARCResources – Exchangeable Shares”.

 

4.                                       Exchangeable Share Support Agreement dated January 31, 2001among the trust, 908563 Alberta Ltd. (the predecessor to ARC Subco) ARCResources and Computershare Trust Company of Canada, as amended.  For information, see “Share Capital of ARCResources – Exchangeable Shares”.

 

5.                                       Amended and Restated Credit Agreement dated as of March 24,2006 between ARC Resources and a syndicate of lenders, and an administrativeagent and a further amendment dated as of March 30, 2007 for an extendiblerevolving credit facility up to Cdn. $800 million.  For information, see “Other InformationRelating to Our Business - Borrowings”.

 

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6.                                       Amended and Restated Uncommitted Master Shelf Agreement as of December 15,2005 between ARC Resources and various purchasers for an aggregate principalamount of US $150 million.  Forinformation, see “Other Information Relating to Our Business - Borrowings”.

 

7.                                       Note Agreement as of April 27, 2004 between ARC Resources andvarious purchasers for US $62.5 million 4.62 per cent Senior Secured Notes – Series Adue April 27, 2014 and US $62.5 million 5.10 per cent Senior Secured Notes– Series B due April 27, 2016. For information, see “Other Information Relating to Our Business -Borrowings”.

 

Copies of each of these documents have beenfiled on SEDAR at www.sedar.com.

 

**INTEREST OF EXPERTS**

** **

There is no person or company whoseprofession or business gives authority to a statement made by such person orcompany and who is named as having prepared or certified a statement, report orvaluation described or included in a filing, or referred to in a filing, madeunder National Instrument 51-102 by us during, or related to, our most recentlycompleted financial year other than GLJ, our independent engineering evaluator,and Deloitte & Touche LLP, our auditors.  As at the date hereof the designatedprofessionals of GLJ Petroleum Consultants Ltd., as a group, beneficiallyowned, directly or indirectly, less than one per cent of our outstanding securities,including the securities of our associates and affiliates.  Deloitte & Touche LLP is the auditorof the Trust and is independent within the meaning of the Rules ofProfessional Conduct of the Institute of Chartered Accountants, Alberta.

 

In addition, none of the aforementionedpersons or companies, nor any director, officer or employee of any of theaforementioned persons or companies, is or is expected to be elected, appointedor employed as a director, officer or employee of ARC Resources or of any ofour associate or affiliate entities. Allan R. Twa, the Corporate Secretary of ARC Resources, is a partner of Burnet, Duckworth & Palmer LLP, which law firm renders legal services to us.

 

**ADDITIONAL INFORMATION**

** **

Additional information including remunerationand indebtedness of directors and officers of ARC Resources, principal holdersof the Trust Units, Exchangeable Shares and rights to purchase Trust Units, iscontained in the Information Circular - Proxy Statement of the Trust whichrelates to the Annual Meeting of Unitholders to be held on May 12,2008.  Additional financial informationis provided in our consolidated financial statements and accompanyingmanagement’s discussion and analysis for the year ended December 31, 2007,which have been filed on SEDAR at www.sedar.com.

 

59

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** **

**APPENDIX AFORM 51-101F2**

** **

**REPORT ONRESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR**

** **

To theboard of directors of ARC Resources Ltd. (the “Company”) on behalf of ARCEnergy Trust (the “Trust”):

 

1.             We have prepared anevaluation of the Company’s and other Trust’s subsidiaries’ reserves data as atDecember 31, 2007.  The reservesdata are estimates of proved reserves and probable reserves and related futurenet revenues as at December 31, 2007 estimated using forecast prices andcosts.

 

2.             The reserves data are theresponsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data basedon our evaluation.

 

We carried out our evaluationin accordance with standards set out in the Canadian Oil and Gas EvaluationHandbook (the “COGE Handbook”) prepared jointly by the Society of PetroleumEvaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining,Metallurgy & Petroleum (Petroleum Society).

 

3.             Those standards require that we plan and perform an evaluation toobtain reasonable assurance as to whether the reserves data are free ofmaterial misstatement.  An evaluationalso includes assessing whether the reserves data are in accordance withprinciples and definitions presented in the COGE Handbook.

 

4.             The following table setsforth the estimated future net revenue (before deduction of income taxes)attributed to proved plus probable reserves, estimated using forecast pricesand costs and calculated using a discount rate of 10 per cent, included in thereserves data of the Company evaluated by us for the year ended December 31,2007, and identifies the respective portions thereof that we have evaluated andreported on to the Company’s board of directors:

 
| **Independent   Qualified Reserves** | ** ** | **Description and  Preparation Date of ** | ** ** | **Location of   Reserves (Country  or Foreign** | ** ** | **Net Present Value of Future Net Revenue  (before income taxes, 10% discount rate, millions dollars)** | ** ** |
|------------------------------------------------|------------|---------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Evaluator**                                  | ** ** | **Evaluation Report**                                    | ** ** | **Geographic Area)**                                           | ** ** | **Audited**                                                                                                                                                              | ** ** | **Evaluated** | ** ** | **Reviewed** | ** ** | **Total** | ** ** |
|                                           |       |                                                          |       |                                                                |       |                                                                                                                                                                     |       |   |   |   |   |   |   |
| GLJ Petroleum Consultants Ltd.                 |       | January 28, 2008                                         |       | Canada                                                              |       | —                                                                                                                                                                   |       | $ | 4,651 |   | — |   | $ | 4,651 |   |
|                                                |            |                                                               |            |                                                                     |            |                                                                                                                                                                          |            |  |  |  |  |  |  |  |  |

 

5.             In our opinion, the reserves data respectively evaluated by us have,in all material respects, been determined and are in accordance with the COGEHandbook.

 

6.             We have no responsibilityto update this evaluation for events and circumstances occurring after thepreparation dates.

 

7.             Because the reserves dataare based on judgments regarding future events, actual results will vary andthe variations may be material; however, any variations should be consistentwith the fact that reserves are categorized according to the probability oftheir recovery.

 

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Executedas to our report referred to above:

 

 
| GLJ Petroleum Consultants Ltd.          |   | Dated March 5, 2008 |
|-----------------------------------------|--------|--------------------------|
| Calgary, Alberta, Canada                |   |                     |
|                                    |   |                     |
|                                    |   |                     |
| *(signed) “James H. Willmon”* |   |                     |
| James H. Willmon, P.Eng                 |   |                     |
| Vice President                          |   |                     |

 

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** **

**APPENDIX BFORM 51-101F3**

** **

**REPORT OFMANAGEMENT AND DIRECTORS ONRESERVES DATA AND OTHER INFORMATION**

** **

Management of ARC Resources Ltd. (the “Company”)on behalf of ARC Energy Trust (the “Trust”) are responsible for the preparationand disclosure of information with respect to the Company’s and the other Trust’ssubsidiaries’ oil and gas activities in accordance with securities regulatoryrequirements. This information includes reserves data, which are estimates ofproved reserves and probable reserves and related future net revenues as at December 31,2007 estimated using forecast prices and costs.

 

An independent qualified reserves evaluatorhas evaluated the Company’s and the other Trust’s subsidiaries’ reserves data.The report of the independent qualified reserves evaluator is presented below.

 

The Reserves Committee of the board ofdirectors of the Company has

 

(a)                                  reviewed the Company’s procedures for providing information to theindependent qualified reserves evaluator;

 

(b)                                 met with the independent qualified reserves evaluator to determinewhether any restrictions affected the ability of the independent qualifiedreserves evaluator to report without reservation; and

 

(c)                                  reviewed the reserves data with management and the independentqualified reserves evaluator.

 

The Reserves Committee of the board ofdirectors has reviewed the Company’s procedures for assembling and reportingother information associated with oil and gas activities and has reviewed thatinformation with management. The board of directors has, on the recommendationof the Reserves Committee, approved

 

(a)                                  the content and filing with securities regulatory authorities of Form 51-101F1containing reserves data and other oil and gas information;

 

(b)                                 the filing of Form 51-101F2 which is the report of theindependent qualified reserves evaluator on the reserves data; and

 

(c)                                  the content and filing of this report.

 

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Because the reserves data are based onjudgments regarding future events, actual results will vary and the variationsmay be material.  However, any variationsshould be consistent with the fact that reserves are categorized according tothe probability of their recovery.

 
| (signed) “*John  P. Dielwart*”           |       | (signed) “*Myron  Stadnyk*”              |
|----------------------------------------------------|------------|----------------------------------------------------|
| **JOHN P. DIELWART**                               | ** ** | **MYRON STADNYK**                                  |
| President and Chief Executive Officer              |       | Senior Vice-President and Chief Operating  Officer |
|                                               |       |                                               |
|                                               |       |                                               |
| (signed) “*Frederic  Coles*”             |       | (signed) “*Fred  J. Dyment*”             |
| **FREDERIC COLES**                                 | ** ** | **FRED J. DYMENT**                                 |
| Director and Chairman****of the Reserves Committee |       | Director and Member of the Reserves Committee      |
|                                               |       |                                               |
|                                               |       |                                               |
| March 18, 2008                                |       |                                               |

 

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** **

**APPENDIX C**

** **

**MANDATE OFTHE AUDIT COMMITTEE**

** **

**Roleand Objective**

** **

The Audit Committee (the “Committee”)is a committee of the Board of Directors of ARC Resources Ltd. (“ARL”) to whichthe Board has delegated its responsibility for oversight of the nature andscope of the annual audit, management’s reporting on internal accountingstandards and practices, financial information and accounting systems andprocedures, financial reporting and statements and recommending, for Board ofDirector approval, the audited financial statements and other mandatorydisclosure releases containing financial information.  The objectives of the Committee, with respectto ARL and ARC Energy Trust (the “Trust”) (hereinafter collectively referred toas “ARC”), are as follows:

 

·                                          To assist Directors to meet theirresponsibilities in respect of the preparation and disclosure of the financialstatements of ARC and related matters.

 

·                                          To provide better communication betweendirectors and external auditors.

 

·                                          To ensure the external auditors’ independence.

 

·                                          To increase the credibility and objectivity offinancial reports.

 

·                                          To strengthen the role of the outside directorsby facilitating in depth discussions between directors on the Committee,management and external auditors.

 

**Mandateand Responsibilities of Committee**

** **

·                                          It is the responsibility of the Committee tosatisfy itself on behalf of the Board with respect to ARC’s internal controlsystems:

 

·                                          identifying, monitoring and mitigating business risks.

 

·                                          ensuring compliance with legal and regulatory requirements.

 

·                                          It is a primary responsibility of the Committeeto review the annual and quarterly financial statements of ARC prior to theirsubmission to the Board of Directors for approval.  The process should include but not be limitedto:

 

·                                          reviewing changes in accounting principles, or in their application,which may have a material impact on the current or future years’ financialstatements;

 

·                                          reviewing significant accruals, reserves or other estimates such asthe ceiling test calculation;

 

·                                          reviewing accounting treatment of unusual or non-recurringtransactions;

 

·                                          reviewing the Trust’s status as a “mutual fund trust” under the *Income Tax Act* (Canada);

 

·                                          ascertaining compliance with covenants under loan agreements andTrust Indenture;

 

·                                          reviewing financial reporting relating to asset retirementobligations;

 

·                                          reviewing disclosure requirements for commitments and contingencies;

 

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·                                          reviewing adjustments raised by the external auditors, whether ornot included in the financial statements;

 

·                                          reviewing unresolved differences between management and the externalauditors;

 

·                                          obtain explanations of significant variances with comparativereporting periods; and

 

·                                          determine through inquiry if there are any related partytransactions and ensure the nature and extent of such transactions are properlydisclosed.

 

·                                          The Committee is to review the financialstatements and related information included in prospectuses, managementdiscussion and analysis (MD&A), information circular-proxy statements andannual information forms (AIF), prior to Board approval.

 

·                                          With respect to the appointment of externalauditors by the Board, the Committee shall:

 

·                                          be directly responsible for overseeing the work of the externalauditors engaged for the purpose of issuing an auditors’ report or performingother audit, review or attest services for the Trust, including the resolutionof disagreements between management and the external auditor regardingfinancial reporting;

 

·                                          review management’s recommendation for the appointment of externalauditors and recommend to the Board appointment of external auditors and thecompensation of the external auditors;

 

·                                          review the terms of engagement of the external auditors, including theappropriateness and reasonableness of the auditors’ fees;

 

·                                          when there is to be a change in auditors, review the issues relatedto the change and the information to be included in the required notice tosecurities regulators of such change; and

 

·                                          review and approve any non-audit services to be provided by theexternal auditors’ firm and consider the impact on the independence of theauditors.

 

·                                          Review with external auditors (and internalauditor if one is appointed by ARC) their assessment of the internal controlsof ARC, their written reports containing recommendations for improvement, andmanagement’s response and follow-up to any identified weaknesses.  The Committee shall also review annually withthe external auditors their plan for their audit and, upon completion of theaudit, their reports upon the financial statements of ARC and its subsidiaries.

 

·                                          Review all public disclosure containing auditedor unaudited financial information before release.

 

·                                          Review financial reporting relating to riskexposure.

 

·                                          Review ARC’s plans and strategies aroundinvestment practices, banking performance and treasury risk management.

 

·                                          Satisfy itself that adequate procedures are in place for the reviewof the Trust’s public disclosure of financial information from the Trust’sfinancial statements and periodically assess the adequacy of those procedures.

 

·                                          Establish procedures for:

 

·                                          the receipt, retention and treatment of complaints received by theTrust regarding accounting, internal accounting controls, or auditing matters;and

 

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·                                          the confidential, anonymous submission by employees of the Trust ofconcerns regarding questionable accounting or auditing matters.

 

·                                          Review and approve ARC’s hiring policiesregarding partners, employees and former partners and employees of the presentand external auditors of ARC.

 

·                                          Review any other matters that the AuditCommittee feels are important to its mandate or that the Board chooses todelegate to it.

 

·                                          Undertake annually a review of this mandate andmake recommendations to the Policy and Board Governance Committee as toproposed changes.

 

**Composition**

** **

·                                          This Committee shall be composed of at leastthree individuals appointed by the Board from amongst its members, all of whichmembers will be independent (within the meaning of Multilateral Instrument52-110 Audit Committees) unless the Board determines to rely on an exemption inNI 52-110.  “Independent” generally meansfree from any business or other direct or indirect material relationship withARC that could, in the view of the Board of Directors, reasonably interfere withthe exercise of the member’s independent judgment.

 

·                                          The Secretary to the Board shall act asSecretary of the Committee.

 

·                                          A quorum shall be a majority of the members ofthe Committee.

 

·                                          All of the members must be financially literatewithin the meaning of NI 52-110 unless the Board has determined to rely on anexemption in NI 52-110.  Being “financiallyliterate” means members have the ability to read and understand a set offinancial statements that present a breadth and level of complexity ofaccounting issues that are generally comparable to the breadth and complexityof issues that can reasonably be expected to be raised by the Trust’s financialstatements.

 

**Meetings**

** **

·                                          The Committee shall meet at least four timesper year and/or as deemed appropriate by the Committee Chair.

 

·                                          The Committee shall meet not less thanquarterly with the auditors, independent of the presence of management.

 

·                                          Agendas, with input from management, shall becirculated to Committee members and relevant management personnel along withbackground information on a timely basis prior to the Committee meetings.

 

·                                          Minutes of each meeting shall be prepared bythe Secretary to the Committee.

 

·                                          The Chief Executive Officer and the ChiefFinancial Officer or their designates shall be available to attend at allmeetings of the Committee upon the invitation of the Committee.

 

·                                          The Controller, Treasurer and such other staffas appropriate to provide information to the Committee shall attend meetingsupon invitation by the Committee.

 

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**Reporting/ Authority**

** **

·                                          Following each meeting, in addition to a verbalreport, the Committee will report to the Board by way of providing copies ofthe minutes of such Committee meeting at the next Board meeting after a meetingis held (these may still be in draft form).

 

·                                          Supporting schedules and information reviewedby the Committee shall be available for examination by any director.

 

·                                          The Committee shall have the authority toinvestigate any financial activity of the Corporation and to communicatedirectly with the internal and external auditors.  All employees are to cooperate as requestedby the Committee.

 

The Committee may retain, andset and pay the compensation for, persons having special expertise and/orobtain independent professional advice to assist in fulfilling its duties andresponsibilities at the expense of ARC.

 

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